Appalachian Power 10-K 28 Feb 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information	12 Months Ended
	Dec. 31, 2016USD ($)shares
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	4,904
Document Type	10-K
Document Period End Date	Dec. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float | $	$ 34,464,089,033
Entity Common Stock, Shares Outstanding	491,711,928
Appalachian Power Co [Member]
Entity Registrant Name	APPALACHIAN POWER CO
Entity Central Index Key	6,879
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	13,499,500
Indiana Michigan Power Co [Member]
Entity Registrant Name	INDIANA MICHIGAN POWER CO
Entity Central Index Key	50,172
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	1,400,000
Ohio Power Co [Member]
Entity Registrant Name	OHIO POWER CO
Entity Central Index Key	73,986
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	27,952,473
Public Service Co Of Oklahoma [Member]
Entity Registrant Name	PUBLIC SERVICE CO OF OKLAHOMA
Entity Central Index Key	81,027
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	9,013,000
Southwestern Electric Power Co [Member]
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER CO
Entity Central Index Key	92,487
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding	7,536,640

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Revenues
Vertically Integrated Utilities	$ 9,012.4	$ 9,069.9		$ 9,396.8
Transmission and Distribution Utilities	4,328.3	4,392		4,552.6
Generation and Marketing	2,858.7	2,866.7		2,384.3
Other Revenues	180.7	124.6		44.9
TOTAL REVENUES	16,380.1	16,453.2		16,378.6
Expenses
Fuel and Other Consumables Used for Electric Generation	2,908.9	3,348.1		4,271.8
Purchased Electricity for Resale	2,821.4	2,760.1		2,085.9
Other Operation	2,956.9	2,703.9		2,766.6
Maintenance	1,237.7	1,325.3		1,328
Asset Impairments and Other Related Charges	2,267.8	0		0
Depreciation and Amortization	1,962.3	2,009.7		1,897.6
Taxes Other Than Income Taxes	1,018	972.6		901.3
TOTAL EXPENSES	15,173	13,119.7		13,251.2
OPERATING INCOME (LOSS)	1,207.1	3,333.5		3,127.4
Other Income (Expense):
Interest and Investment Income	16.3	7.9		7.4
Carrying Costs Income	16.2	23.5		33.2
Allowance for Equity Funds Used During Construction	113.2	131.9		102.9
Interest Expense	(877.2)	(873.9)		(868)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	475.6	2,622.9		2,402.9
Income Tax Expense (Credit)	(73.7)	919.6		902.6
Equity Earnings (Loss) of Unconsolidated Subsidiaries	71.2	65.3		90.2
Income from Continuing Operations	620.5	1,768.6		1,590.5
Income from Discontinued Operations, Net of Tax	(2.5)	283.7		47.5
NET INCOME (LOSS)	618	2,052.3		1,638
Net Income Attributable to Noncontrolling Interests	7.1	5.2		4.2
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 610.9	$ 2,047.1		$ 1,633.8
Earnings Per Share
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	491,495,458	490,340,522		488,592,997
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$ 1.25	$ 3.59		$ 3.24
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	(0.01)	0.58		0.10
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 1.24	$ 4.17		$ 3.34
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	491,662,007	490,574,568		488,899,840
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS	$ 1.25	$ 3.59		$ 3.24
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM DISCONTINUED OPERATIONS	(0.01)	0.58		0.10
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 1.24	$ 4.17		$ 3.34
Appalachian Power Co [Member]
Revenues
Vertically Integrated Utilities	$ 2,847.4	$ 2,805.6		$ 2,899.4
Sales to AEP Affiliates	142.1	147.8		144.5
Other Revenues	11.7	10.1		9.2
TOTAL REVENUES	3,001.2	2,963.5		3,053.1
Expenses
Fuel and Other Consumables Used for Electric Generation	654.9	675.9		813.4
Purchased Electricity for Resale	329.3	395.2		456.6
Purchased Electricity from AEP Affiliates	0	0		4.7
Other Operation	486.7	405.4		427.7
Maintenance	275	263.3		259.3
Depreciation and Amortization	388.5	388.8		400.9
Taxes Other Than Income Taxes	123.5	124.1		122.3
TOTAL EXPENSES	2,257.9	2,252.7		2,484.9
OPERATING INCOME (LOSS)	743.3	710.8		568.2
Other Income (Expense):
Interest Income	1.3	1.4		1.6
Carrying Costs Income	0.4	1.2		3
Allowance for Equity Funds Used During Construction	11.7	13.8		7.1
Interest Expense	(188.5)	(192.3)		(209.6)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	568.2	534.9		370.3
Income Tax Expense (Credit)	199.1	194.3		154.9
NET INCOME (LOSS)	369.1	340.6		215.4
Indiana Michigan Power Co [Member]
Revenues
Vertically Integrated Utilities	2,062.3	2,073.3		2,149.1
Sales to AEP Affiliates	26.2	27.4		4.2
Other Revenues - Affiliated	62.1	78.8		94.4
Other Revenues	17	6.7		2
TOTAL REVENUES	2,167.6	2,186.2		2,249.7
Expenses
Fuel and Other Consumables Used for Electric Generation	284.1	336.3		476.6
Purchased Electricity for Resale	198.7	195.8		96.8
Purchased Electricity from AEP Affiliates	228.6	232.1		270
Other Operation	572	553.4		586
Maintenance	205.6	212		228.5
Asset Impairments and Other Related Charges	10.5	0		0
Depreciation and Amortization	191.7	198.4		200.2
Taxes Other Than Income Taxes	94.8	88.3		86.4
TOTAL EXPENSES	1,786	1,816.3		1,944.5
OPERATING INCOME (LOSS)	381.6	369.9		305.2
Other Income (Expense):
Interest Income	11.3	9.6		4.6
Allowance for Equity Funds Used During Construction	15.3	11.6		18.9
Interest Expense	(100.8)	(90.2)		(93.5)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	307.4	300.9		235.2
Income Tax Expense (Credit)	67.5	96.1		79.6
NET INCOME (LOSS)	239.9	204.8		155.6
Ohio Power Co [Member]
Revenues
Transmission and Distribution Utilities	2,930.1	3,056.1		3,204.9
Sales to AEP Affiliates	17.3	84.1		165.2
Other Revenues	6.5	8.5		6.8
TOTAL REVENUES	2,953.9	3,148.7		3,376.9
Expenses
Purchased Electricity for Resale	663.1	635		282
Purchased Electricity from AEP Affiliates	141.9	527.1		1,349.7
Generation Deferrals	(82.7)	(30.7)	[1]	(157)	[1]
Amortization of Generation Deferrals	242.9	169.1		110.9
Other Operation	706.8	630.3		594.8
Maintenance	148	166.8		196
Depreciation and Amortization	238.6	217.5		213.7
Taxes Other Than Income Taxes	386.8	372.8		353.3
TOTAL EXPENSES	2,445.4	2,687.9		2,943.4
OPERATING INCOME (LOSS)	508.5	460.8		433.5
Other Income (Expense):
Interest Income	3.8	5.6		10
Carrying Costs Income	19.9	11.8		26.5
Allowance for Equity Funds Used During Construction	6	8.8		6.9
Interest Expense	(112.2)	(127.8)		(128.3)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	426	359.2		348.6
Income Tax Expense (Credit)	143.8	126.5		132.2
NET INCOME (LOSS)	282.2	232.7		216.4
Public Service Co Of Oklahoma [Member]
Revenues
Vertically Integrated Utilities	1,242.8	1,331.4		1,340.3
Sales to AEP Affiliates	2.6	4.6		7.1
Other Revenues	4.4	3.2		4.2
TOTAL REVENUES	1,249.8	1,339.2		1,351.6
Expenses
Fuel and Other Consumables Used for Electric Generation	44.8	301.4		258
Purchased Electricity for Resale	441.2	316.9		385
Purchased Electricity from AEP Affiliates	3.7	0		11
Other Operation	288.5	268.4		262.8
Maintenance	106.9	104.6		108
Depreciation and Amortization	130.2	117.5		101
Taxes Other Than Income Taxes	35.8	37.2		37
TOTAL EXPENSES	1,051.1	1,146		1,162.8
OPERATING INCOME (LOSS)	198.7	193.2		188.8
Other Income (Expense):
Interest Income	0.7	0.4		0.2
Allowance for Equity Funds Used During Construction	6.2	8.8		3.1
Interest Expense	(51.2)	(58.6)		(54.6)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	154.4	143.8		137.5
Income Tax Expense (Credit)	54.4	51.3		50.6
NET INCOME (LOSS)	100	92.5		86.9
Southwestern Electric Power Co [Member]
Revenues
Vertically Integrated Utilities	1,721.5	1,762.3		1,817.9
Sales to AEP Affiliates	24.5	16.6		26.3
Other Revenues	2	2		2.2
TOTAL REVENUES	1,748	1,780.9		1,846.4
Expenses
Fuel and Other Consumables Used for Electric Generation	517.8	570.6		650.4
Purchased Electricity for Resale	142.4	110.6		178.1
Purchased Electricity from AEP Affiliates	0	0		3.8
Other Operation	331.7	294.5		272.8
Maintenance	149.7	155.9		149.2
Depreciation and Amortization	196.5	192		185.1
Taxes Other Than Income Taxes	88.8	88.1		84.3
TOTAL EXPENSES	1,426.9	1,411.7		1,523.7
OPERATING INCOME (LOSS)	321.1	369.2		322.7
Other Income (Expense):
Interest Income	1.5	1.2		0.3
Allowance for Equity Funds Used During Construction	11	26.4		11.9
Interest Expense	(119.7)	(119.9)		(126.1)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	213.9	276.9		208.8
Income Tax Expense (Credit)	52.1	84.8		66.4
Equity Earnings (Loss) of Unconsolidated Subsidiaries	7.9	3.9		2.2
NET INCOME (LOSS)	169.7	196		144.6
Net Income Attributable to Noncontrolling Interests	4.1	3.7		4.2
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 165.6	$ 192.3		$ 140.4
[1]	Amounts exclude $31 million and $157 million in 2015 and 2014, respectively, which are now presented as Generation Deferrals on the Statement of Income.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Income (Loss)	$ 618	$ 2,052.3	$ 1,638
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(16.4)	(4.9)	5.3
Securities Available for Sale, Net of Tax	1.3	(0.6)	0.9
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0.6	1.2	4.8
Pension and OPEB Funded Status, Net of Tax	(14.7)	(25.7)	1.1
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(29.2)	(30)	12.1
TOTAL COMPREHENSIVE INCOME (LOSS)	588.8	2,022.3	1,650.1
Total Comprehensive Income Attributable to Noncontrolling Interest	7.1	5.2	4.2
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	581.7	2,017.1	1,645.9
Appalachian Power Co [Member]
Net Income (Loss)	369.1	340.6	215.4
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.7)	(0.3)	0.7
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(1.4)	(1.8)	(1.3)
Pension and OPEB Funded Status, Net of Tax	(3.5)	(5.7)	2.7
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(5.6)	(7.8)	2.1
TOTAL COMPREHENSIVE INCOME (LOSS)	363.5	332.8	217.5
Indiana Michigan Power Co [Member]
Net Income (Loss)	239.9	204.8	155.6
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1.3	1.1	1.5
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0	0	0.2
Pension and OPEB Funded Status, Net of Tax	(0.8)	(3.5)	(0.5)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0.5	(2.4)	1.2
TOTAL COMPREHENSIVE INCOME (LOSS)	240.4	202.4	156.8
Ohio Power Co [Member]
Net Income (Loss)	282.2	232.7	216.4
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(1.3)	(1.3)	(1.5)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(1.3)	(1.3)	(1.5)
TOTAL COMPREHENSIVE INCOME (LOSS)	280.9	231.4	214.9
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	100	92.5	86.9
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(0.8)	(0.8)	(0.8)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(0.8)	(0.8)	(0.8)
TOTAL COMPREHENSIVE INCOME (LOSS)	99.2	91.7	86.1
Southwestern Electric Power Co [Member]
Net Income (Loss)	169.7	196	144.6
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1.7	2	2.2
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(0.7)	(1)	(0.9)
Pension and OPEB Funded Status, Net of Tax	(1)	(2.9)	(0.3)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	0	(1.9)	1
TOTAL COMPREHENSIVE INCOME (LOSS)	169.7	194.1	145.6
Total Comprehensive Income Attributable to Noncontrolling Interest	4.1	3.7	4.2
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO SHAREHOLDERS	$ 165.6	$ 190.4	$ 141.4

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flow Hedges, Tax	$ (8.8)	$ (2.6)	$ 2.9
Securities Available for Sale, Tax	0.7	(0.3)	0.4
Amortization of Pension and OPEB Deferred Costs, Tax	0.3	0.6	2.6
Pension and OPEB Funded Status, Tax	(7.9)	(13.9)	0.6
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	(0.4)	(0.1)	0.4
Amortization of Pension and OPEB Deferred Costs, Tax	(0.8)	(1)	(0.7)
Pension and OPEB Funded Status, Tax	(1.9)	(3.1)	1.5
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	0.7	0.6	0.8
Amortization of Pension and OPEB Deferred Costs, Tax	0	0	0.1
Pension and OPEB Funded Status, Tax	(0.4)	(1.9)	(0.3)
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(0.7)	(0.7)	(0.8)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(0.4)	(0.4)	(0.4)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	0.9	1.1	1.2
Amortization of Pension and OPEB Deferred Costs, Tax	(0.4)	(0.5)	(0.5)
Pension and OPEB Funded Status, Tax	$ (0.5)	$ (1.6)	$ (0.2)

Condensed Consolidated Statemen

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Appalachian Power Co [Member]	Indiana Michigan Power Co [Member]	Ohio Power Co [Member]	Public Service Co Of Oklahoma [Member]	Southwestern Electric Power Co [Member]	Common Stock [Member]	Common Stock [Member]Appalachian Power Co [Member]	Common Stock [Member]Indiana Michigan Power Co [Member]	Common Stock [Member]Ohio Power Co [Member]	Common Stock [Member]Public Service Co Of Oklahoma [Member]	Common Stock [Member]Southwestern Electric Power Co [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]Appalachian Power Co [Member]	Additional Paid-in Capital [Member]Indiana Michigan Power Co [Member]	Additional Paid-in Capital [Member]Ohio Power Co [Member]	Additional Paid-in Capital [Member]Public Service Co Of Oklahoma [Member]	Additional Paid-in Capital [Member]Southwestern Electric Power Co [Member]	Retained Earnings [Member]		Retained Earnings [Member]Appalachian Power Co [Member]	Retained Earnings [Member]Indiana Michigan Power Co [Member]	Retained Earnings [Member]Ohio Power Co [Member]	Retained Earnings [Member]Public Service Co Of Oklahoma [Member]	Retained Earnings [Member]Southwestern Electric Power Co [Member]	Accumulated Other Comprehensive Income [Member]	Accumulated Other Comprehensive Income [Member]Appalachian Power Co [Member]	Accumulated Other Comprehensive Income [Member]Indiana Michigan Power Co [Member]	Accumulated Other Comprehensive Income [Member]Ohio Power Co [Member]	Accumulated Other Comprehensive Income [Member]Public Service Co Of Oklahoma [Member]	Accumulated Other Comprehensive Income [Member]Southwestern Electric Power Co [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member]Southwestern Electric Power Co [Member]
Common Stock, Dividends, Per Share, Declared	$ 2.03
Beginning Balance at Dec. 31, 2013	$ 16,085.6	$ 3,229.4	$ 1,922.2	$ 1,625.3	$ 942.1	$ 2,055.9	$ 3,302.7	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,131.2	$ 1,809.6	$ 980.9	$ 663.8	$ 364	$ 674.6	$ 6,766.1		$ 1,156.5	$ 900.2	$ 633.2	$ 415.1	$ 1,253.6	$ (115.2)	$ 2.9	$ (15.5)	$ 7.1	$ 5.8	$ (8.5)	$ 0.8	$ 0.5
Beginning Balance, Shares at Dec. 31, 2013	508,113,964						508,100,000
Issuance of Common Stock, Value	$ 73.6						$ 10.6						63
Issuance of Common Stock, Shares	1,625,195						1,600,000
Capital Contributions from Parent				175												175
Common Stock Dividends	$ (997.6)																		(993.3)	[1]
Common Stock Dividends		(80)	(125)	(35)		(100)															(80)	(125)	(35)		(100)
Common Stock Dividends						(4.3)																										(4.3)	(4.3)
Stockholders' Equity, Other	12.8												9.2																			3.6
Net Income (Loss)																			1,633.8						140.4
Net Income (Loss) Attributable to Noncontrolling Interests	4.2					4.2																										4.2	4.2
Net Income (Loss)	1,638	215.4	155.6	216.4	86.9	144.6															215.4	155.6	216.4	86.9
Other Comprehensive Income (Loss)	12.1	2.1	1.2	(1.5)	(0.8)	1																				12.1	2.1	1.2	(1.5)	(0.8)	1
Contribution of Amos Plant from Parent		0
Contribution of Mutual Energy SWEPCo, LLC from Parent						0
Ending Balance at Dec. 31, 2014	$ 16,824.5	3,366.9	1,954	1,980.2	1,028.2	2,097.2	$ 3,313.3	260.4	56.6	321.2	157.2	135.7	6,203.4	1,809.6	980.9	838.8	364	674.6	7,406.6		1,291.9	930.8	814.6	502	1,294	(103.1)	5	(14.3)	5.6	5	(7.5)	4.3	0.4
Ending Balance, Shares at Dec. 31, 2014	509,739,159						509,700,000
Common Stock, Dividends, Per Share, Declared	$ 2.15
Issuance of Common Stock, Value	$ 81.6						$ 10.7						70.9
Issuance of Common Stock, Shares	1,650,014						1,700,000
Capital Contributions from Parent				0
Common Stock Dividends	$ (1,059)																		(1,055.4)	[1]
Common Stock Dividends		(243.8)	(120)	(225)		(120)															(243.8)	(120)	(225)		(120)
Common Stock Dividends						(3.6)																										(3.6)	(3.6)
Stockholders' Equity, Other	29.5												22.2																			7.3
Net Income (Loss)																			2,047.1						192.3
Net Income (Loss) Attributable to Noncontrolling Interests	5.2					3.7																										5.2	3.7
Net Income (Loss)	2,052.3	340.6	204.8	232.7	92.5	196															340.6	204.8	232.7	92.5
Other Comprehensive Income (Loss)	(30)	(7.8)	(2.4)	(1.3)	(0.8)	(1.9)																				(30)	(7.8)	(2.4)	(1.3)	(0.8)	(1.9)
Pension and OPEB Adjustment Related to Mitchell Plant	6																									6
Contribution of Amos Plant from Parent		19.1												19.1
Contribution of Mutual Energy SWEPCo, LLC from Parent						2												2
Ending Balance at Dec. 31, 2015	$ 17,904.9	3,475	2,036.4	1,986.6	$ 1,119.9	2,169.7	$ 3,324	260.4	56.6	321.2	157.2	135.7	6,296.5	1,828.7	980.9	838.8	364	676.6	8,398.3		1,388.7	1,015.6	822.3	594.5	1,366.3	(127.1)	(2.8)	(16.7)	4.3	4.2	(9.4)	13.2	0.5
Ending Balance, Shares at Dec. 31, 2015	511,389,173				10,482,000		511,400,000
Common Stock, Dividends, Per Share, Declared	$ 2.27
Issuance of Common Stock, Value	$ 34.2						$ 4.3						29.9
Issuance of Common Stock, Shares	659,347						600,000
Capital Contributions from Parent				0
Common Stock Dividends	$ (1,121)																		(1,116.8)	[1]
Common Stock Dividends		(255)	(125)	(150)	$ (5)	(120)															(255)	(125)	(150)	(5)	(120)
Common Stock Dividends						(4.2)																										(4.2)	(4.2)
Stockholders' Equity, Other	13.2												6.2																			7
Net Income (Loss)																			610.9						165.6
Net Income (Loss) Attributable to Noncontrolling Interests	7.1					4.1																										7.1	4.1
Net Income (Loss)	618	369.1	239.9	282.2	100	169.7															369.1	239.9	282.2	100
Other Comprehensive Income (Loss)	(29.2)	(5.6)	0.5	(1.3)	(0.8)	0																				(29.2)	(5.6)	0.5	(1.3)	(0.8)
Contribution of Amos Plant from Parent		0
Contribution of Mutual Energy SWEPCo, LLC from Parent						0
Ending Balance at Dec. 31, 2016	$ 17,420.1	$ 3,583.5	$ 2,151.8	$ 2,117.5	$ 1,214.1	$ 2,215.2	$ 3,328.3	$ 260.4	$ 56.6	$ 321.2	$ 157.2	$ 135.7	$ 6,332.6	$ 1,828.7	$ 980.9	$ 838.8	$ 364	$ 676.6	$ 7,892.4		$ 1,502.8	$ 1,130.5	$ 954.5	$ 689.5	$ 1,411.9	$ (156.3)	$ (8.4)	$ (16.2)	$ 3	$ 3.4	$ (9.4)	$ 23.1	$ 0.4
Ending Balance, Shares at Dec. 31, 2016	512,048,520				10,482,000		512,000,000
[1]	(a)Cash dividends declared per AEP common share were $2.27, $2.15 and $2.03 for the years ended December 31, 2016, 2015 and 2014, respectively.

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions		Dec. 31, 2016		Dec. 31, 2015
Current Assets
Cash and Cash Equivalents		$ 210.5		$ 176.4
Other Temporary Investments		331.7		386.8
Accounts Receivable:
Customers		705.1		615.9
Accrued Unbilled Revenues		158.7		31.2
Pledged Accounts Receivable - AEP Credit		972.7		940.3
Miscellaneous		118.1		82.1
Allowance for Uncollectible Accounts		(37.9)		(29)
Total Accounts Receivable		1,916.7		1,640.5
Fuel		423.8		600.8
Materials and Supplies		543.5		738.6
Risk Management Assets – Nonaffiliated		94.5		134.4
Regulatory Asset for Under-Recovered Fuel Costs		156.6		115.2
Margin Deposits		79.9		107.3
Assets Held for Sale		1,951.2		0
Prepayments and Other Current Assets		325.5		172.4
TOTAL CURRENT ASSETS		6,033.9		4,072.4
Property, Plant and Equipment
Generation		19,848.9		25,559.8
Transmission		16,658.7		14,247.9
Distribution		18,900.8		18,046.9
Other Property, Plant and Equipment		3,444.3		3,722.9
Construction Work in Progress		3,183.9		3,903.9
Total Property, Plant and Equipment		62,036.6		65,481.4
Accumulated Depreciation and Amortization		16,397.3		19,348.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		45,639.3	[1]	46,133.2
Other Noncurrent Assets
Regulatory Assets		5,625.5		5,140.3
Securitized Assets		1,486.1		1,749.9
Spent Nuclear Fuel and Decommissioning Trusts		2,256.2		2,106.4
Goodwill		52.5		52.5
Long-term Risk Management Assets		289.1		321.8
Deferred Charges and Other Noncurrent Assets		2,085.1		2,106.6
TOTAL OTHER NONCURRENT ASSETS		11,794.5		11,477.5
TOTAL ASSETS		63,467.7		61,683.1
Current Liabilities
Accounts Payable		1,688.5		1,418
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[2]	673		675
Other Short-term Debt		1,040		125
Total Short-term Debt		1,713		800
Long-term Debt Due Within One Year		2,878		1,831.8
Risk Management Liabilities		53.4		87.1
Customer Deposits		343.2		346.6
Accrued Taxes		1,048		979.1
Accrued Interest		227.2		226.9
Obligations Under Capital Leases		63.4		96.2
Regulatory Liability for Over-Recovered Fuel Costs		8		113.9
Liabilities Held for Sale		235.9		0
Other Current Liabilities		1,302.8		1,305.1
TOTAL CURRENT LIABILITIES		9,498		7,108.5
Noncurrent Liabilities
Long-term Debt		17,378.4		17,740.9
Long-term Debt - Affiliated		0		0
Long-term Risk Management Liabilities		316.2		179.1
Deferred Income Taxes		11,884.4		11,733.2
Regulatory Liabilities and Deferred Investment Tax Credits		3,751.3		3,736.1
Asset Retirement Obligations		1,830.6		1,806.5
Employee Benefits and Pension Obligations		614.1		583.3
Obligations Under Capital Leases		242.1		247.3
Deferred Credits and Other Noncurrent Liabilities		774.6		890.6
TOTAL NONCURRENT LIABILITIES		36,549.6		36,669.7
TOTAL LIABILITIES		46,047.6		43,778.2
Rate Matters
Commitments and Contingencies
Equity
Common Stock		3,328.3		3,324
Paid-in Capital		6,332.6		6,296.5
Retained Earnings		7,892.4		8,398.3
Accumulated Other Comprehensive Income (Loss)		(156.3)		(127.1)
TOTAL COMMON SHAREHOLDER'S EQUITY		17,397		17,891.7
Noncontrolling Interests		23.1		13.2
TOTAL EQUITY		17,420.1		17,904.9
TOTAL LIABILITIES AND EQUITY		63,467.7		61,683.1
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		2.7		2.8
Restricted Cash for Securitized Funding		15.8		14.8
Advances to Affiliates		24.1		25.6
Accounts Receivable:
Customers		131.4		120.9
Affiliated Companies		54.4		51.2
Accrued Unbilled Revenues		52.7		17.9
Miscellaneous		0.9		2.2
Allowance for Uncollectible Accounts		(3.5)		(4.3)
Total Accounts Receivable		235.9		187.9
Fuel		112		119.3
Materials and Supplies		98.8		127
Risk Management Assets – Nonaffiliated		2.6		14.7
Risk Management Assets - Affiliated		0		0.9
Accrued Tax Benefits		4.2		30.6
Regulatory Asset for Under-Recovered Fuel Costs		68.4		86.9
Margin Deposits		17.5		7.9
Prepayments and Other Current Assets		9.7		9.5
TOTAL CURRENT ASSETS		591.7		627.9
Property, Plant and Equipment
Generation		6,332.8		6,200.8
Transmission		2,796.9		2,408.1
Distribution		3,569.1		3,402.5
Other Property, Plant and Equipment		373.5		345.5
Construction Work in Progress		390.3		475.1
Total Property, Plant and Equipment		13,462.6		12,832
Accumulated Depreciation and Amortization		3,636.8		3,407.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,825.8		9,424.4
Other Noncurrent Assets
Regulatory Assets		1,121.1		1,154.2
Securitized Assets		305.3		328
Long-term Risk Management Assets		0		0.1
Deferred Charges and Other Noncurrent Assets		133.3		113.7
TOTAL OTHER NONCURRENT ASSETS		1,559.7		1,596
TOTAL ASSETS		11,977.2		11,648.3
Current Liabilities
Advances from Affiliates		79.6		181
Accounts Payable		253.7		196.5
Affiliated Companies		82.6		67.7
Short-term Debt:
Long-term Debt Due Within One Year		503.1		318
Risk Management Liabilities		0.3		4.8
Customer Deposits		83.1		83.9
Accrued Taxes		107.6		79.5
Obligations Under Capital Leases		6.8		6.3
Other Current Liabilities		170.1		194
TOTAL CURRENT LIABILITIES		1,280.1		1,125.4
Noncurrent Liabilities
Long-term Debt		3,530.8		3,612.7
Long-term Risk Management Liabilities		0.9		0.1
Deferred Income Taxes		2,672.3		2,527
Regulatory Liabilities and Deferred Investment Tax Credits		627.8		637.1
Asset Retirement Obligations		108.8		98.9
Employee Benefits and Pension Obligations		108.5		114.4
Obligations Under Capital Leases		38.2		39.1
Deferred Credits and Other Noncurrent Liabilities		64.5		57.7
TOTAL NONCURRENT LIABILITIES		7,113.6		7,047.9
TOTAL LIABILITIES		8,393.7		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		1,502.8		1,388.7
Accumulated Other Comprehensive Income (Loss)		(8.4)		(2.8)
TOTAL EQUITY		3,583.5		3,475
TOTAL LIABILITIES AND EQUITY		11,977.2		11,648.3
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		1.2		1.1
Advances to Affiliates		12.5		11.7
Accounts Receivable:
Customers		60.2		43.9
Affiliated Companies		51		68.7
Accrued Unbilled Revenues		1.5		0.1
Miscellaneous		0.7		2.6
Allowance for Uncollectible Accounts		0		(0.1)
Total Accounts Receivable		113.4		115.2
Fuel		32.3		46.5
Materials and Supplies		150.8		185.9
Risk Management Assets – Nonaffiliated		3.5		10.6
Risk Management Assets - Affiliated		0		1.7
Accrued Tax Benefits		37.7		40.5
Regulatory Asset for Under-Recovered Fuel Costs		26.1		11.6
Accrued Reimbursement of Spent Nuclear Fuel Costs		22.1		6
Prepayments and Other Current Assets		19.9		24.5
TOTAL CURRENT ASSETS		419.5		455.3
Property, Plant and Equipment
Generation		4,056.1		3,841.7
Transmission		1,472.8		1,406.9
Distribution		1,899.3		1,790.8
Other Property, Plant and Equipment		550.2		662.3
Construction Work in Progress		654.2		519.8
Total Property, Plant and Equipment		8,632.6		8,221.5
Accumulated Depreciation and Amortization		3,005.1		3,018
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,627.5		5,203.5
Other Noncurrent Assets
Regulatory Assets		916.6		804.3
Spent Nuclear Fuel and Decommissioning Trusts		2,256.2		2,106.4
Deferred Charges and Other Noncurrent Assets		121.5		140.9
TOTAL OTHER NONCURRENT ASSETS		3,294.3		3,051.6
TOTAL ASSETS		9,341.3		8,710.4
Current Liabilities
Advances from Affiliates		215.2		294.3
Accounts Payable		179		201
Affiliated Companies		75.6		61.8
Short-term Debt:
Long-term Debt Due Within One Year		209.3		162.9
Risk Management Liabilities		0.3		6.3
Customer Deposits		34.3		35.7
Accrued Taxes		77.2		74.2
Accrued Interest		31.7		26.2
Obligations Under Capital Leases		9.4		32.8
Regulatory Liability for Over-Recovered Fuel Costs		0		0.3
Other Current Liabilities		123.4		142.1
TOTAL CURRENT LIABILITIES		955.4		1,037.3
Noncurrent Liabilities
Long-term Debt		2,262.1		1,837.1
Long-term Risk Management Liabilities		0.8		1.6
Deferred Income Taxes		1,527.4		1,361.5
Regulatory Liabilities and Deferred Investment Tax Credits		1,065.5		1,076.2
Asset Retirement Obligations		1,257.9		1,240.9
Obligations Under Capital Leases		35.3		30.2
Deferred Credits and Other Noncurrent Liabilities		120.4		119.4
TOTAL NONCURRENT LIABILITIES		6,234.1		5,636.7
TOTAL LIABILITIES		7,189.5		6,674
Rate Matters
Commitments and Contingencies
Equity
Common Stock		56.6		56.6
Paid-in Capital		980.9		980.9
Retained Earnings		1,130.5		1,015.6
Accumulated Other Comprehensive Income (Loss)		(16.2)		(16.7)
TOTAL EQUITY		2,151.8		2,036.4
TOTAL LIABILITIES AND EQUITY		9,341.3		8,710.4
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		3.1		3.1
Restricted Cash for Securitized Funding		27.2		27.7
Advances to Affiliates		24.2		331.1
Accounts Receivable:
Customers		51.1		46.4
Affiliated Companies		66.3		64.3
Accrued Unbilled Revenues		21		1.4
Miscellaneous		0.9		0.4
Allowance for Uncollectible Accounts		(0.4)		(0.2)
Total Accounts Receivable		138.9		112.3
Materials and Supplies		45.9		61.5
Emission Allowances		20.4		24.6
Risk Management Assets – Nonaffiliated		0.2		0
Prepayments and Other Current Assets		11		12.9
TOTAL CURRENT ASSETS		270.9		573.2
Property, Plant and Equipment
Transmission		2,319.2		2,235.6
Distribution		4,457.2		4,287.7
Other Property, Plant and Equipment		443.7		408.2
Construction Work in Progress		221.5		171.9
Total Property, Plant and Equipment		7,441.6		7,103.4
Accumulated Depreciation and Amortization		2,116		2,048.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,325.6		5,054.7
Other Noncurrent Assets
Notes Receivable - Affiliated		32.3		32.3
Regulatory Assets		1,107.5		1,113
Securitized Assets		62.1		85.9
Long-term Risk Management Assets		0		19.2
Deferred Charges and Other Noncurrent Assets		295.5		259.6
TOTAL OTHER NONCURRENT ASSETS		1,497.4		1,510
TOTAL ASSETS		7,093.9		7,137.9
Current Liabilities
Accounts Payable		175.4		156.4
Affiliated Companies		95.6		88.7
Short-term Debt:
Long-term Debt Due Within One Year		46.4		395.9
Risk Management Liabilities		5.9		3.6
Customer Deposits		71		65.4
Accrued Taxes		520.3		528.3
Accrued Interest		31.2		33
Obligations Under Capital Leases		4.2		3.9
Regulatory Liability for Over-Recovered Fuel Costs		4.2		27.6
Other Current Liabilities		236		154.3
TOTAL CURRENT LIABILITIES		1,181.8		1,425.6
Noncurrent Liabilities
Long-term Debt		1,717.5		1,761.8
Long-term Risk Management Liabilities		113.1		0
Deferred Income Taxes		1,346.1		1,383.2
Regulatory Liabilities and Deferred Investment Tax Credits		506.2		514.2
Employee Benefits and Pension Obligations		27.8		35.8
Obligations Under Capital Leases		8.1		9.3
Deferred Credits and Other Noncurrent Liabilities		83.9		30.7
TOTAL NONCURRENT LIABILITIES		3,794.6		3,725.7
TOTAL LIABILITIES		4,976.4		5,151.3
Rate Matters
Commitments and Contingencies
Equity
Common Stock		321.2		321.2
Paid-in Capital		838.8		838.8
Retained Earnings		954.5		822.3
Accumulated Other Comprehensive Income (Loss)		3		4.3
TOTAL EQUITY		2,117.5		1,986.6
TOTAL LIABILITIES AND EQUITY		7,093.9		7,137.9
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		1.5		1.4
Advances to Affiliates		0		80.6
Accounts Receivable:
Customers		27.5		26
Affiliated Companies		26.8		20.8
Miscellaneous		4.4		3.3
Allowance for Uncollectible Accounts		(0.2)		(0.6)
Total Accounts Receivable		58.5		49.5
Fuel		22.9		17.6
Materials and Supplies		44.6		51.9
Risk Management Assets – Nonaffiliated		0.8		0.6
Accrued Tax Benefits		27.3		37.3
Regulatory Asset for Under-Recovered Fuel Costs		33.8		0
Prepayments and Other Current Assets		6		6.5
TOTAL CURRENT ASSETS		195.4		245.4
Property, Plant and Equipment
Generation		1,559.3		1,302.6
Transmission		832.8		815.4
Distribution		2,322.4		2,206.7
Other Property, Plant and Equipment		233.2		405.7
Construction Work in Progress		148.2		315.3
Total Property, Plant and Equipment		5,095.9		5,045.7
Accumulated Depreciation and Amortization		1,272.7		1,352.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,823.2		3,693.2
Other Noncurrent Assets
Regulatory Assets		340.2		214.8
Employee Benefits and Pension Assets		10.4		10.6
Deferred Charges and Other Noncurrent Assets		10		6.4
TOTAL OTHER NONCURRENT ASSETS		360.6		231.8
TOTAL ASSETS		4,379.2		4,170.4
Current Liabilities
Advances from Affiliates		52		0
Accounts Payable		116.3		108.2
Affiliated Companies		56.2		51.5
Short-term Debt:
Long-term Debt Due Within One Year		0.5		275.4
Risk Management Liabilities		0		0.2
Customer Deposits		49.7		50.3
Accrued Taxes		21		23.6
Accrued Interest		13.9		15.1
Obligations Under Capital Leases		4.1		3.7
Regulatory Liability for Over-Recovered Fuel Costs		0		76.1
Provision for Refund		46.1		0
Other Current Liabilities		47.8		64.4
TOTAL CURRENT LIABILITIES		403.5		664.8
Noncurrent Liabilities
Long-term Debt		1,285.5		1,010.7
Deferred Income Taxes		1,058.8		971.8
Regulatory Liabilities and Deferred Investment Tax Credits		339.7		335.1
Asset Retirement Obligations		52.8		39.9
Employee Benefits and Pension Obligations		13.6		14.5
Obligations Under Capital Leases		9.8		10.9
Deferred Credits and Other Noncurrent Liabilities		11.2		13.7
TOTAL NONCURRENT LIABILITIES		2,761.6		2,385.7
TOTAL LIABILITIES		3,165.1		3,050.5
Rate Matters
Commitments and Contingencies
Equity
Common Stock		157.2		157.2
Paid-in Capital		364		364
Retained Earnings		689.5		594.5
Accumulated Other Comprehensive Income (Loss)		3.4		4.2
TOTAL EQUITY		1,214.1		1,119.9
TOTAL LIABILITIES AND EQUITY		4,379.2		4,170.4
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		10.3		5.2
Advances to Affiliates		169.8		2
Accounts Receivable:
Customers		48.5		40.2
Affiliated Companies		29.3		22
Miscellaneous		17.5		27.1
Allowance for Uncollectible Accounts		(1.2)		(0.9)
Total Accounts Receivable		94.1		88.4
Fuel		107.1		142.1
Materials and Supplies		68.4		71.5
Risk Management Assets – Nonaffiliated		0.9		0.8
Accrued Tax Benefits		51.5		0
Regulatory Asset for Under-Recovered Fuel Costs		8.4		4.1
Prepayments and Other Current Assets		35.5		21.2
TOTAL CURRENT ASSETS		546		335.3
Property, Plant and Equipment
Generation		4,607.6		3,943.5
Transmission		1,584.2		1,387.8
Distribution		2,020.6		1,957.3
Other Property, Plant and Equipment		670.4		883.5
Construction Work in Progress		113.8		751.3
Total Property, Plant and Equipment		8,996.6		8,923.4
Accumulated Depreciation and Amortization		2,567.1		2,602.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,429.5		6,321.1
Other Noncurrent Assets
Regulatory Assets		551.2		415.8
Deferred Charges and Other Noncurrent Assets		99.9		75.8
TOTAL OTHER NONCURRENT ASSETS		651.1		491.6
TOTAL ASSETS		7,626.6		7,148
Current Liabilities
Advances from Affiliates		0		58.3
Accounts Payable		117.5		150.4
Affiliated Companies		68.5		78.8
Short-term Debt:
Long-term Debt Due Within One Year		353.7		3.3
Risk Management Liabilities		0.3		3.1
Customer Deposits		62.1		61.4
Accrued Taxes		40.9		58.3
Accrued Interest		45.1		43
Obligations Under Capital Leases		11.8		21.9
Regulatory Liability for Over-Recovered Fuel Costs		3.8		8.4
Other Current Liabilities		83.9		110.7
TOTAL CURRENT LIABILITIES		783.8		589.2
Noncurrent Liabilities
Long-term Debt		2,325.4		2,270.2
Long-term Risk Management Liabilities		0		2.1
Deferred Income Taxes		1,606.9		1,399.8
Regulatory Liabilities and Deferred Investment Tax Credits		438.9		448.8
Asset Retirement Obligations		147.1		117.5
Employee Benefits and Pension Obligations		34.1		25.8
Obligations Under Capital Leases		65.5		75.6
Deferred Credits and Other Noncurrent Liabilities		9.7		49.3
TOTAL NONCURRENT LIABILITIES		4,627.6		4,389.1
TOTAL LIABILITIES		5,411.4		4,978.3
Rate Matters
Commitments and Contingencies
Equity
Common Stock		135.7		135.7
Paid-in Capital		676.6		676.6
Retained Earnings		1,411.9		1,366.3
Accumulated Other Comprehensive Income (Loss)		(9.4)		(9.4)
TOTAL COMMON SHAREHOLDER'S EQUITY		2,214.8		2,169.2
Noncontrolling Interests		0.4		0.5
TOTAL EQUITY		2,215.2		2,169.7
TOTAL LIABILITIES AND EQUITY		$ 7,626.6		$ 7,148
[1]	Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
[2]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Current Assets
Cash and Cash Equivalents	$ 210.5	$ 176.4
Other Temporary Investments	331.7	386.8
Fuel	423.8	600.8
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	3,444.3	3,722.9
Accumulated Depreciation and Amortization	16,397.3	19,348.2
Current Liabilities
Long-term Debt Due Within One Year	2,878	1,831.8
Noncurrent Liabilities
Long-term Debt	$ 17,378.4	$ 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	512,048,520	511,389,173
Treasury Stock, Shares	20,336,592	20,336,592
Ohio Phase-In-Recovery Funding [Member]
Current Liabilities
Long-term Debt Due Within One Year	$ 46.3	$ 45.9
Noncurrent Liabilities
Long-term Debt	93.9	139.4
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	2.7	2.8
Fuel	112	119.3
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	373.5	345.5
Accumulated Depreciation and Amortization	3,636.8	3,407.6
Current Liabilities
Long-term Debt Due Within One Year	503.1	318
Noncurrent Liabilities
Long-term Debt	$ 3,530.8	$ 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	$ 1.2	$ 1.1
Fuel	32.3	46.5
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	550.2	662.3
Accumulated Depreciation and Amortization	3,005.1	3,018
Current Liabilities
Long-term Debt Due Within One Year	209.3	162.9
Noncurrent Liabilities
Long-term Debt	$ 2,262.1	$ 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	$ 130.9	$ 84.6
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	3.1	3.1
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	443.7	408.2
Accumulated Depreciation and Amortization	2,116	2,048.7
Current Liabilities
Long-term Debt Due Within One Year	46.4	395.9
Noncurrent Liabilities
Long-term Debt	$ 1,717.5	$ 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
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	$ 1.5	$ 1.4
Fuel	22.9	17.6
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	233.2	405.7
Accumulated Depreciation and Amortization	1,272.7	1,352.5
Current Liabilities
Long-term Debt Due Within One Year	0.5	275.4
Noncurrent Liabilities
Long-term Debt	$ 1,285.5	$ 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	$ 10.3	$ 5.2
Fuel	107.1	142.1
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	670.4	883.5
Accumulated Depreciation and Amortization	2,567.1	2,602.3
Current Liabilities
Long-term Debt Due Within One Year	353.7	3.3
Noncurrent Liabilities
Long-term Debt	$ 2,325.4	$ 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	$ 8.7	$ 3.7
Fuel	34.3	40.4
Property, Plant and Equipment, Gross [Abstract]
Other Property, Plant and Equipment	267.5	297.7
Accumulated Depreciation and Amortization	155.6	157.3
Subsidiaries [Member]
Current Assets
Other Temporary Investments	322.5	376.6
Current Liabilities
Long-term Debt Due Within One Year	427.5	410.4
Noncurrent Liabilities
Long-term Debt	$ 1,737.5	$ 1,971.4

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Operating Activites
Net Income (Loss)	$ 618	$ 2,052.3		$ 1,638
Income from Discontinued Operations, Net of Tax	(2.5)	283.7		47.5
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest	620.5	1,768.6		1,590.5
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	1,962.3	2,009.7		1,897.6
Deferred Income Taxes	(50)	808.2		868.8
Asset Impairments and Other Related Charges	2,267.8	0		0
Carrying Costs Income	(16.2)	(23.5)		(33.2)
Allowance for Equity Funds Used During Construction	(113.2)	(131.9)		(102.9)
Mark-to-Market of Risk Management Contracts	150.8	52.5		(53.1)
Amortization of Nuclear Fuel	128.6	145		144.2
Pension and Postemployment Benefit Reserves	21.6	33.2		77.2
Pension Contributions to Qualified Plan Trust	(84.8)	(91.8)		(70.3)
Property Taxes	(19)	(52.4)		(41.8)
Deferred Fuel Over/Under-Recovery, Net	(65.5)	137.8		(35.5)
Deferral of Ohio Capacity Costs, Net	88.1	65.5		(113.5)
Provision for Refund - Global Settlement	120.3	0		0
Disposition of Tanners Creek Plant Site	(93.5)	0		0
Change in Other Noncurrent Assets	(438.4)	(105.7)		35.6
Change in Other Noncurrent Liabilities	15.4	(89)		256.1
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(226.6)	200.2		(60.3)
Fuel, Materials and Supplies	60.2	(38.6)		100.8
Accounts Payable	164.9	16.5		(74.9)
Accrued Taxes, Net	42.8	120.2		0.4
Other Current Assets	14.2	(26.7)		(20.6)
Other Current Liabilities	(28.5)	(49.1)		237.3
Net Cash Flows from (Used for) Operating Activities	4,521.8	4,748.7		4,602.4
Investing Activities
Construction Expenditures	(4,781.1)	(4,508)		(4,130)
Change in Other Temporary Investments, Net	57.4	9.6		(31.1)
Purchases of Investment Securities	(3,002.3)	(2,282.7)		(1,088)
Sales of Investment Securities	2,957.7	2,218.4		1,031.8
Acquisitions of Nuclear Fuel	(128.5)	(92)		(116.2)
Acquisitions of Assets	(107.9)	(5.3)		(64.8)
Other Investing Activities	15.6	96		(7.6)
Net Cash Flows from (Used for) Investing Activities	(4,989.1)	(4,564)		(4,405.9)
Financing Activities
Issuance of Common Stock, Net	34.2	81.6		73.6
Issuance of Long-term Debt	2,594.9	3,436.6		2,067
Change in Short-term Debt, Net	913	(546)		589
Retirement of Long-term Debt	(1,794.9)	(2,397.9)		(1,777.4)
Make Whole Premium on Extinguishment of Long-term Debt	0	(92.7)		0
Principal Payments for Capital Lease Obligations	(106.6)	(99)		(111.2)
Dividends Paid on Common Stock	(1,121)	(1,059)		(997.6)
Other Financing Activities	(15.7)	14.7		5.7
Net Cash Flows from (Used for) Financing Activities	503.9	(661.7)		(150.9)
Cash Provided by (Used in) Operating Activities, Discontinued Operations	(2.5)	69.8		11.1
Cash Provided by (Used in) Investing Activities, Discontinued Operations	0	548.8		(0.1)
Cash Provided by (Used in) Financing Activities, Discontinued Operations	0	(127.7)		(11.6)
Net Increase (Decrease) in Cash and Cash Equivalents	34.1	13.9		45
Cash and Cash Equivalents at Beginning of Period	176.4	162.5		117.5
Cash and Cash Equivalents at End of Period	210.5	176.4		162.5
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	848.5	857.2		838.5
Net Cash Paid (Received) for Income Taxes	29.5	120.2		117.3
Noncash Acquisitions Under Capital Leases	86.1	150.2		135.1
Construction Expenditures Included in Current Liabilities as of December 31,	858	741.4		559.3
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	2.1	37.9		44.5
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	0.7	2.2		3.4
Appalachian Power Co [Member]
Operating Activites
Net Income (Loss)	369.1	340.6		215.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	388.5	388.8		400.9
Deferred Income Taxes	130.7	227.5		144.7
Carrying Costs Income	(0.4)	(1.2)		(3)
Allowance for Equity Funds Used During Construction	(11.7)	(13.8)		(7.1)
Mark-to-Market of Risk Management Contracts	9.4	4.8		3.3
Pension Contributions to Qualified Plan Trust	(8.8)	(10)		(9)
Deferred Fuel Over/Under-Recovery, Net	22.2	(19.4)		(119.6)
Change in Other Noncurrent Assets	3.4	(56.9)		(14.9)
Change in Other Noncurrent Liabilities	(26.1)	(34.4)		51.8
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(48)	51.7		68.6
Fuel, Materials and Supplies	12.9	(10.9)		76
Accounts Payable	19.5	0.3		(62.8)
Accrued Taxes, Net	53.7	(60.2)		(5.4)
Other Current Assets	(9.8)	(4.2)		(1)
Other Current Liabilities	(9.9)	(10.3)		23.8
Net Cash Flows from (Used for) Operating Activities	894.7	792.4		761.7
Investing Activities
Construction Expenditures	(646.7)	(636.2)		(497.4)
Change in Advances to Affiliates, Net	1.5	22.9		44
Other Investing Activities	12.3	13.9		(5.5)
Net Cash Flows from (Used for) Investing Activities	(632.9)	(599.4)		(458.9)
Financing Activities
Issuance of Long-term Debt	314	726.3		394.2
Change in Advances from Affiliates, Net	(101.4)	181		0
Retirement of Long-term Debt	(213.6)	(672.6)		(612.7)
Retirement of Long-term Debt - Affiliated	0	(86)		0
Make Whole Premium on Extinguishment of Long-term Debt	0	(92.7)		0
Principal Payments for Capital Lease Obligations	(6.4)	(5.5)		(5.6)
Dividends Paid on Common Stock	(255)	(243.8)		(80)
Other Financing Activities	0.5	0.5		1.2
Net Cash Flows from (Used for) Financing Activities	(261.9)	(192.8)		(302.9)
Net Increase (Decrease) in Cash and Cash Equivalents	(0.1)	0.2		(0.1)
Cash and Cash Equivalents at Beginning of Period	2.8	2.6		2.7
Cash and Cash Equivalents at End of Period	2.7	2.8		2.6
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	181.8	196.7		196.7
Net Cash Paid (Received) for Income Taxes	22.1	30.4		15.9
Noncash Acquisitions Under Capital Leases	6.1	31.8		4.9
Construction Expenditures Included in Current Liabilities as of December 31,	151.6	90.4		72
Noncash Contribution of Amos Plant from Parent	0	19.1		0
Indiana Michigan Power Co [Member]
Operating Activites
Net Income (Loss)	239.9	204.8		155.6
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	191.7	198.4		200.2
Deferred Income Taxes	105.1	94.2		70.2
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expenses, Net	(48.4)	11.2		20
Asset Impairments and Other Related Charges	10.5	0		0
Allowance for Equity Funds Used During Construction	(15.3)	(11.6)		(18.9)
Mark-to-Market of Risk Management Contracts	2	14.6		(6.1)
Amortization of Nuclear Fuel	128.6	145		144.2
Pension Contributions to Qualified Plan Trust	(12.7)	(14.6)		(8.9)
Deferred Fuel Over/Under-Recovery, Net	(14.8)	(17.7)		7.8
Disposition of Tanners Creek Plant Site	(93.5)	0		0
Change in Other Noncurrent Assets	(66.5)	(19.9)		(74.5)
Change in Other Noncurrent Liabilities	58.2	13.8		93.7
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	0.5	16		32.3
Fuel, Materials and Supplies	20.9	11.7		7.8
Accounts Payable	11.6	3.7		(20.4)
Accrued Taxes, Net	6	(14.3)		24.8
Other Current Assets	8	(4.8)		10.6
Other Current Liabilities	(2.1)	(7)		6.9
Net Cash Flows from (Used for) Operating Activities	529.7	623.5		645.3
Investing Activities
Construction Expenditures	(596.9)	(459.8)		(484.7)
Change in Advances to Affiliates, Net	(0.8)	1.8		42.4
Purchases of Investment Securities	(3,000)	(2,272)		(1,086.4)
Sales of Investment Securities	2,957.7	2,218.4		1,031.8
Acquisitions of Nuclear Fuel	(128.5)	(92)		(116.2)
Other Investing Activities	8.4	9.4		10.4
Net Cash Flows from (Used for) Investing Activities	(760.1)	(594.2)		(602.7)
Financing Activities
Issuance of Long-term Debt	569.4	310.7		205.6
Change in Advances from Affiliates, Net	(79.1)	151.8		142.5
Retirement of Long-term Debt	(100.2)	(332.1)		(218.5)
Principal Payments for Capital Lease Obligations	(35.3)	(40.2)		(48.1)
Dividends Paid on Common Stock	(125)	(120)		(125)
Other Financing Activities	0.7	0.6		0.6
Net Cash Flows from (Used for) Financing Activities	230.5	(29.2)		(42.9)
Net Increase (Decrease) in Cash and Cash Equivalents	0.1	0.1		(0.3)
Cash and Cash Equivalents at Beginning of Period	1.1	1		1.3
Cash and Cash Equivalents at End of Period	1.2	1.1		1
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	83.3	84.5		81.6
Net Cash Paid (Received) for Income Taxes	(39.5)	21.2		(10.2)
Noncash Acquisitions Under Capital Leases	18.2	3		16.4
Construction Expenditures Included in Current Liabilities as of December 31,	106.2	95.8		66.1
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,	2.1	37.9		44.5
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage	0.7	2.2		3.4
Ohio Power Co [Member]
Operating Activites
Net Income (Loss)	282.2	232.7		216.4
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	238.6	217.5		213.7
Generation Deferrals	(82.7)	(30.7)	[1]	(157)	[1]
Amortization of Generation Deferrals	242.9	169.1		110.9
Deferred Income Taxes	(39.2)	37.6		74.4
Carrying Costs Income	(19.9)	(11.8)		(26.5)
Allowance for Equity Funds Used During Construction	(6)	(8.8)		(6.9)
Mark-to-Market of Risk Management Contracts	134.6	31.7		(44.5)
Pension Contributions to Qualified Plan Trust	(7.1)	(7.7)		(6.5)
Property Taxes	(9.8)	(24.7)		(4.6)
Purchased Electricity Over Under Recovery Net	(23.3)	(18.7)		62.1
Provision for Refund - Global Settlement	120.3	0		0
Change in Regulatory Assets	(139.8)	86.2		115.7
Change in Other Noncurrent Assets	(44.6)	(52.9)		(41.4)
Change in Other Noncurrent Liabilities	31	27.9		97.1
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(26.6)	61.9		(29.8)
Fuel, Materials and Supplies	(2.1)	(25.2)		(7.2)
Accounts Payable	13.7	(64.3)		(30.3)
Accrued Taxes, Net	(6)	111.8		(7.2)
Other Current Assets	0	(2.8)		1.5
Other Current Liabilities	(9.9)	2.4		27.7
Net Cash Flows from (Used for) Operating Activities	646.3	731.2		557.6
Investing Activities
Construction Expenditures	(416.2)	(453.3)		(453.5)
Change in Restricted Cash for Securitized Funding	0.5	1		(9.3)
Change in Advances to Affiliates, Net	306.9	(18.6)		26.6
Proceeds from Notes Receivable - Affiliated	0	86		178.6
Other Investing Activities	12	13.1		2.5
Net Cash Flows from (Used for) Investing Activities	(96.8)	(371.8)		(255.1)
Financing Activities
Capital Contributions from Parent	0	0		175
Retirement of Long-term Debt	(395.9)	(131.5)		(438.6)
Principal Payments for Capital Lease Obligations	(4.2)	(3.9)		(5.1)
Dividends Paid on Common Stock	(150)	(225)		(35)
Other Financing Activities	0.6	1.2		1.1
Net Cash Flows from (Used for) Financing Activities	(549.5)	(359.2)		(302.6)
Net Increase (Decrease) in Cash and Cash Equivalents	0	0.2		(0.1)
Cash and Cash Equivalents at Beginning of Period	3.1	2.9		3
Cash and Cash Equivalents at End of Period	3.1	3.1		2.9
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	109.9	121.6		132.4
Net Cash Paid (Received) for Income Taxes	220.4	26.1		44
Noncash Acquisitions Under Capital Leases	3.4	2.7		4.8
Construction Expenditures Included in Current Liabilities as of December 31,	44.6	34.3		43.4
Public Service Co Of Oklahoma [Member]
Operating Activites
Net Income (Loss)	100	92.5		86.9
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	130.2	117.5		101
Deferred Income Taxes	82.5	58.3		74.7
Allowance for Equity Funds Used During Construction	(6.2)	(8.8)		(3.1)
Mark-to-Market of Risk Management Contracts	(0.4)	(1.4)		1.9
Pension Contributions to Qualified Plan Trust	(5.6)	(5.8)		(4.4)
Deferred Fuel Over/Under-Recovery, Net	(109.9)	111.8		(32.4)
Provision for Refund	46.1	0		0
Change in Regulatory Assets	(16.6)	(14.3)		16.7
Change in Other Noncurrent Assets	(19.3)	(25.7)		(22.6)
Change in Other Noncurrent Liabilities	(0.1)	5		(3.8)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(9)	6.9		8.9
Fuel, Materials and Supplies	2	(2.2)		0.6
Accounts Payable	25.7	6.4		(26.3)
Accrued Taxes, Net	7.4	(10.2)		(5.6)
Other Current Assets	0.8	(1)		(0.8)
Other Current Liabilities	(10.4)	10.2		17.8
Net Cash Flows from (Used for) Operating Activities	217.2	339.2		209.5
Investing Activities
Construction Expenditures	(351.1)	(359.1)		(367.5)
Change in Advances to Affiliates, Net	80.6	(80.6)		0
Other Investing Activities	11	9.2		2.8
Net Cash Flows from (Used for) Investing Activities	(259.5)	(430.5)		(364.7)
Financing Activities
Issuance of Long-term Debt	274.2	248.8		75
Change in Advances from Affiliates, Net	52	(154.2)		117.5
Retirement of Long-term Debt	(275.4)	(0.4)		(34.1)
Principal Payments for Capital Lease Obligations	(3.8)	(3.6)		(3.7)
Dividends Paid on Common Stock	(5)	0		0
Other Financing Activities	0.4	0.7		0.6
Net Cash Flows from (Used for) Financing Activities	42.4	91.3		155.3
Net Increase (Decrease) in Cash and Cash Equivalents	0.1	0		0.1
Cash and Cash Equivalents at Beginning of Period	1.4	1.4		1.3
Cash and Cash Equivalents at End of Period	1.5	1.4		1.4
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	60.1	54.8		52.8
Net Cash Paid (Received) for Income Taxes	(37.7)	7.9		(21.2)
Noncash Acquisitions Under Capital Leases	3.1	3.6		2.3
Construction Expenditures Included in Current Liabilities as of December 31,	33.6	47.4		38.6
Southwestern Electric Power Co [Member]
Operating Activites
Net Income (Loss)	169.7	196		144.6
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	196.5	192		185.1
Deferred Income Taxes	162.6	41.9		239.4
Allowance for Equity Funds Used During Construction	(11)	(26.4)		(11.9)
Mark-to-Market of Risk Management Contracts	(5.1)	3.4		2.1
Pension Contributions to Qualified Plan Trust	(8.3)	(8.1)		(3.8)
Deferred Fuel Over/Under-Recovery, Net	(8.9)	28.3		(13.4)
Change in Regulatory Liabilities	(22)	(21.4)		(24.6)
Change in Other Noncurrent Assets	(13)	(1.6)		(3.6)
Change in Other Noncurrent Liabilities	6	15.4		25.1
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(5.7)	20.5		25.5
Fuel, Materials and Supplies	38.1	(22.9)		6.3
Accounts Payable	3.5	(10.7)		4.4
Accrued Taxes, Net	(68.9)	29.7		(12.8)
Other Current Assets	(13.9)	1.1		(4.4)
Other Current Liabilities	(15.3)	(9.6)		21.2
Net Cash Flows from (Used for) Operating Activities	404.3	427.6		579.2
Investing Activities
Construction Expenditures	(426.3)	(540.6)		(511.4)
Change in Advances to Affiliates, Net	(167.8)	41		(41)
Other Investing Activities	0.1	5.9		5.1
Net Cash Flows from (Used for) Investing Activities	(594)	(493.7)		(547.3)
Financing Activities
Issuance of Long-term Debt	406.7	445.9		99.4
Change in Advances from Affiliates, Net	(58.3)	58.3		(9.2)
Retirement of Long-term Debt	(3.3)	(306.8)		(3.3)
Principal Payments for Capital Lease Obligations	(27.1)	(17.7)		(18.3)
Dividends Paid on Common Stock	(120)	(120)		(100)
Dividends Paid on Common Stock	(4.2)	(3.6)		(4.3)
Other Financing Activities	1	0.8		1
Net Cash Flows from (Used for) Financing Activities	194.8	56.9		(34.7)
Net Increase (Decrease) in Cash and Cash Equivalents	5.1	(9.2)		(2.8)
Cash and Cash Equivalents at Beginning of Period	5.2	14.4		17.2
Cash and Cash Equivalents at End of Period	10.3	5.2		14.4
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	118	112.6		116.9
Net Cash Paid (Received) for Income Taxes	(32)	15.4		(152.2)
Noncash Acquisitions Under Capital Leases	5.9	7.4		4.1
Construction Expenditures Included in Current Liabilities as of December 31,	41.8	92.9		94.3
Noncash Contribution of Mutual Energy SWEPCo, LLC from Parent	0	(2)		0
Noncash Increase in Advances to Affiliates, Net due to Contribution of Mutual Energy SWEPCo, LLC	$ 0	$ 2		$ 0
[1]	Amounts exclude $31 million and $157 million in 2015 and 2014, respectively, which are now presented as Generation Deferrals on the Statement of Income.

Organization and Summary of Sig

Organization and Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2016
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings. Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity
Appalachian Power Co [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings. Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity
Indiana Michigan Power Co [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings. Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity
Ohio Power Co [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings. Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity
Public Service Co Of Oklahoma [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings. Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity
Southwestern Electric Power Co [Member]
Organization and Summary of Significant Accounting Policies	ORGANIZATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES The disclosures in this note apply to all Registrants unless indicated otherwise. ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities. Disposition of AEP River Operations In October 2015, AEP signed an agreement to sell its commercial barge transportation subsidiary, AEPRO, to a nonaffiliated third party. The sale closed in November 2015. The results of operations of AEPRO have been classified as Discontinued Operations on the statements of income for the current period and prior periods presented. The transaction was accounted for in accordance with the accounting guidance for “Presentation of Financial Statements and Property, Plant and Equipment.” Material disclosures within the notes to the financial statements exclude amounts related to Discontinued Operations for all periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement. Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets. See Note 17 − Variable Interest Entities and Note 18 − Property, Plant and Equipment. Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates. Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less. Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. See “Fair Value Measurements of Other Temporary Investments” in Note 11 . Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds. Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost. Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries. See “Sale of Receivables – AEP Credit” section of Note 14 for additional information. Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves. Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements. Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions. Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense. Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.” Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment. Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings. Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity

New Accounting Pronouncements

New Accounting Pronouncements	12 Months Ended
	Dec. 31, 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 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. 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 adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016, initial lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. 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 adopted ASU 2016-09 effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.
Appalachian Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. 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 adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016, initial lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. 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 adopted ASU 2016-09 effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.
Indiana Michigan Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. 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 adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016, initial lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. 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 adopted ASU 2016-09 effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.
Ohio Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. 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 adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016, initial lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. 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 adopted ASU 2016-09 effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.
Public Service Co Of Oklahoma [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. 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 adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016, initial lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. 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 adopted ASU 2016-09 effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.
Southwestern Electric Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrants’ business. The following final pronouncements will impact the financial statements. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, determine the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The FASB deferred implementation of ASU 2014-09 under the terms in ASU 2015-14, “Revenue from Contracts with Customers (Topic: 606): Deferral of the Effective Date.” The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. Management continues to analyze the impact of the new revenue standard and related ASUs. During 2016, initial revenue contract assessments were completed. Material revenue streams were identified within the AEP System and representative contract/transaction types were sampled. Performance obligations identified within each material revenue stream were evaluated to determine whether the obligations were satisfied at a point in time or over time. Contracts determined to be satisfied over time generally qualified for the invoicing practical expedient since the invoiced amounts reasonably represented the value to customers of performance obligations fulfilled to date. Based upon the completed assessments, management does not expect a material impact to the timing of revenue recognized or net income and plans to elect the modified retrospective transition approach upon adoption. Management also continues to monitor unresolved industry implementation issues, including items related to collectability and alternative revenue programs, and will analyze the related impacts to revenue recognition. 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 adopted ASU 2015-11 prospectively, effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-01 “Recognition and Measurement of Financial Assets and Financial Liabilities” (ASU 2016-01) In January 2016, the FASB issued ASU 2016-01 enhancing the reporting model for financial instruments. Under the new standard, equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) are required to be measured at fair value with changes in fair value recognized in net income. The new standard also amends disclosure requirements and requires separate presentation of financial assets and liabilities by measurement category and form of financial asset (that is, securities or loans and receivables) on the balance sheet or the accompanying notes to the financial statements. The amendments also clarify that an entity should evaluate the need for a valuation allowance on a deferred tax asset related to available-for-sale securities in combination with the entity’s other deferred tax assets. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2017 with early adoption permitted. The amendments will be applied by means of a cumulative-effect adjustment to the balance sheet as of the beginning of the fiscal year of adoption. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-01 effective January 1, 2018. ASU 2016-02 “Accounting for Leases” (ASU 2016-02) In February 2016, the FASB issued ASU 2016-02 increasing the transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. Under the new standard, an entity must recognize an asset and liability for operating leases on the balance sheets. Additionally, a capital lease will be known as a finance lease going forward. Leases with lease terms of 12 months or longer will be subject to the new requirements. Fundamentally, the criteria used to determine lease classification will remain the same, but will be more subjective under the new standard. The new accounting guidance is effective for annual periods beginning after December 15, 2018 with early adoption permitted. The guidance will be applied by means of a modified retrospective approach. The modified retrospective approach will require lessees and lessors to recognize and measure leases at the beginning of the earliest period presented. Management continues to analyze the impact of the new lease standard. During 2016, initial lease contract assessments were completed. The AEP System lease population was identified and representative lease contracts were sampled. Based upon the completed assessments, management prepared a system gap analysis to outline new disclosure compliance requirements compared to current system capabilities. Lease system options are currently being evaluated. Management plans to elect certain of the following practical expedients upon adoption: Practical Expedient Description Overall Expedients (for leases commenced prior to adoption date and must be adopted as a package) Do not need to reassess whether any expired or existing contracts are/or contain leases, do not need to reassess the lease classification for any expired or existing leases and do not need to reassess initial direct costs for any existing leases. Lease and Non-lease Components (elect by class of underlying asset) Elect as an accounting policy to not separate non-lease components from lease components and instead account for each lease and associated non-lease component as a single lease component. Short-term Lease (elect by class of underlying asset) Elect as an accounting policy to not apply the recognition requirements to short-term leases. Lease term Elect to use hindsight to determine the lease term. Management expects the new standard to impact financial position, but not results of operations or cash flows. Management also continues to monitor unresolved industry implementation issues, including items related to renewables and PPAs, pole attachments, easements and right-of-ways, and will analyze the related impacts to lease accounting. Management plans to adopt ASU 2016-02 effective January 1, 2019. ASU 2016-09 “Compensation – Stock Compensation” (ASU 2016-09) In March 2016, the FASB issued ASU 2016-09 simplifying the accounting for share-based payment transactions including the income tax consequences, classification of awards as either equity or liabilities and classification on the statements of cash flows. Under the new standard, all excess tax benefits and tax deficiencies (including tax benefits of dividends on share-based payment awards) should be recognized as income tax expense or benefit on the statements of income. Under current GAAP, excess tax benefits are recognized in additional paid-in capital while tax deficiencies are recognized either as an offset to accumulated excess tax benefits, if any, or on the statements of income. 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 adopted ASU 2016-09 effective January 1, 2017. There was no impact on results of operations, financial position or cash flows at adoption. ASU 2016-13 “Measurement of Credit Losses on Financial Instruments” (ASU 2016-13) In June 2016, the FASB issued ASU 2016-13 requiring an allowance to be recorded for all expected credit losses for financial assets. The allowance for credit losses is based on historical information, current conditions and reasonable and supportable forecasts. The new standard also makes revisions to the other than temporary impairment model for available-for-sale debt securities. Disclosures of credit quality indicators in relation to the amortized cost of financing receivables are further disaggregated by year of origination. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2019 with early adoption permitted for interim and annual periods beginning after December 15, 2018. The amendments will be applied through a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2016-13 effective January 1, 2020. ASU 2016-18 “Restricted Cash” (ASU 2016-18) In November 2016, the FASB issued ASU 2016-18 clarifying the treatment of restricted cash on the statements of cash flows. Under the new standard, amounts considered restricted cash will be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts on the statements of cash flows. The new accounting guidance is effective for annual periods beginning after December 15, 2017. Early adoption is permitted in any interim or annual period. The guidance will be applied by means of a retrospective approach. Management is analyzing the impact of the new standard. Management plans to adopt ASU 2016-18 effective for the 2017 Annual Report.

Comprehensive Income

Comprehensive Income	12 Months Ended
	Dec. 31, 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 years ended December 31, 2016 , 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues 59.1 — — — — 59.1 Purchased Electricity for Resale (39.1 ) — — — — (39.1 ) Regulatory Assets/(Liabilities), Net (a) (2.8 ) — — — — (2.8 ) Interest Expense — 6.1 — — — 6.1 Amortization of Prior Service Cost (Credit) — — — (20.6 ) — (20.6 ) Amortization of Actuarial (Gains)/Losses — — — 28.0 — 28.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 17.2 6.1 — 7.4 — 30.7 Income Tax (Expense) Credit 6.0 2.2 — 2.6 — 10.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit — (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ — $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit — (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit — (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.5 ) — — — (0.5 ) Regulatory Assets/(Liabilities), Net (a) (2.2 ) — — — (2.2 ) Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.1 — 3.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.7 ) 1.2 (2.0 ) — (3.5 ) Income Tax (Expense) Credit (0.9 ) 0.4 (0.7 ) — (1.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.0 — — 2.0 Income Tax (Expense) Credit — 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) — 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ — $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 1.7 — — 1.7 Income Tax (Expense) Credit — 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.8 ) — — — (0.8 ) Regulatory Assets/(Liabilities), Net (a) (1.0 ) — — — (1.0 ) Interest Expense — 2.4 — — 2.4 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 1.1 — 1.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.8 ) 2.4 0.3 — 0.9 Income Tax (Expense) Credit (0.6 ) 0.8 0.1 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 4.3 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.9 ) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.9 ) (1.9 ) Income Tax (Expense) Credit — (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) (1.3 ) Balance in AOCI as of December 31, 2016 $ — $ 3.0 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (2.0 ) — — (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (2.0 ) — — (2.0 ) Income Tax (Expense) Credit — (0.7 ) — — (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.2 ) — — — (0.2 ) Interest Expense — (2.1 ) — — (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (2.1 ) — — (2.3 ) Income Tax (Expense) Credit (0.1 ) (0.7 ) — — (0.8 ) 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 December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2016 $ — $ 3.4 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — (0.1 ) Interest Expense — (1.1 ) (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (1.1 ) (1.2 ) Income Tax (Expense) Credit — (0.4 ) (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit — 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ — $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit — 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit — 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — — — (0.1 ) Interest Expense — 3.5 — — 3.5 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) 3.5 (1.4 ) — 2.0 Income Tax (Expense) Credit (0.1 ) 1.3 (0.5 ) — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Appalachian Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2016 , 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues 59.1 — — — — 59.1 Purchased Electricity for Resale (39.1 ) — — — — (39.1 ) Regulatory Assets/(Liabilities), Net (a) (2.8 ) — — — — (2.8 ) Interest Expense — 6.1 — — — 6.1 Amortization of Prior Service Cost (Credit) — — — (20.6 ) — (20.6 ) Amortization of Actuarial (Gains)/Losses — — — 28.0 — 28.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 17.2 6.1 — 7.4 — 30.7 Income Tax (Expense) Credit 6.0 2.2 — 2.6 — 10.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit — (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ — $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit — (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit — (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.5 ) — — — (0.5 ) Regulatory Assets/(Liabilities), Net (a) (2.2 ) — — — (2.2 ) Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.1 — 3.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.7 ) 1.2 (2.0 ) — (3.5 ) Income Tax (Expense) Credit (0.9 ) 0.4 (0.7 ) — (1.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.0 — — 2.0 Income Tax (Expense) Credit — 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) — 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ — $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 1.7 — — 1.7 Income Tax (Expense) Credit — 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.8 ) — — — (0.8 ) Regulatory Assets/(Liabilities), Net (a) (1.0 ) — — — (1.0 ) Interest Expense — 2.4 — — 2.4 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 1.1 — 1.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.8 ) 2.4 0.3 — 0.9 Income Tax (Expense) Credit (0.6 ) 0.8 0.1 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 4.3 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.9 ) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.9 ) (1.9 ) Income Tax (Expense) Credit — (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) (1.3 ) Balance in AOCI as of December 31, 2016 $ — $ 3.0 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (2.0 ) — — (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (2.0 ) — — (2.0 ) Income Tax (Expense) Credit — (0.7 ) — — (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.2 ) — — — (0.2 ) Interest Expense — (2.1 ) — — (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (2.1 ) — — (2.3 ) Income Tax (Expense) Credit (0.1 ) (0.7 ) — — (0.8 ) 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 December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2016 $ — $ 3.4 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — (0.1 ) Interest Expense — (1.1 ) (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (1.1 ) (1.2 ) Income Tax (Expense) Credit — (0.4 ) (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit — 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ — $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit — 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit — 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — — — (0.1 ) Interest Expense — 3.5 — — 3.5 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) 3.5 (1.4 ) — 2.0 Income Tax (Expense) Credit (0.1 ) 1.3 (0.5 ) — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Indiana Michigan Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2016 , 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues 59.1 — — — — 59.1 Purchased Electricity for Resale (39.1 ) — — — — (39.1 ) Regulatory Assets/(Liabilities), Net (a) (2.8 ) — — — — (2.8 ) Interest Expense — 6.1 — — — 6.1 Amortization of Prior Service Cost (Credit) — — — (20.6 ) — (20.6 ) Amortization of Actuarial (Gains)/Losses — — — 28.0 — 28.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 17.2 6.1 — 7.4 — 30.7 Income Tax (Expense) Credit 6.0 2.2 — 2.6 — 10.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit — (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ — $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit — (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit — (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.5 ) — — — (0.5 ) Regulatory Assets/(Liabilities), Net (a) (2.2 ) — — — (2.2 ) Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.1 — 3.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.7 ) 1.2 (2.0 ) — (3.5 ) Income Tax (Expense) Credit (0.9 ) 0.4 (0.7 ) — (1.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.0 — — 2.0 Income Tax (Expense) Credit — 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) — 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ — $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 1.7 — — 1.7 Income Tax (Expense) Credit — 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.8 ) — — — (0.8 ) Regulatory Assets/(Liabilities), Net (a) (1.0 ) — — — (1.0 ) Interest Expense — 2.4 — — 2.4 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 1.1 — 1.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.8 ) 2.4 0.3 — 0.9 Income Tax (Expense) Credit (0.6 ) 0.8 0.1 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 4.3 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.9 ) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.9 ) (1.9 ) Income Tax (Expense) Credit — (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) (1.3 ) Balance in AOCI as of December 31, 2016 $ — $ 3.0 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (2.0 ) — — (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (2.0 ) — — (2.0 ) Income Tax (Expense) Credit — (0.7 ) — — (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.2 ) — — — (0.2 ) Interest Expense — (2.1 ) — — (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (2.1 ) — — (2.3 ) Income Tax (Expense) Credit (0.1 ) (0.7 ) — — (0.8 ) 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 December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2016 $ — $ 3.4 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — (0.1 ) Interest Expense — (1.1 ) (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (1.1 ) (1.2 ) Income Tax (Expense) Credit — (0.4 ) (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit — 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ — $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit — 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit — 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — — — (0.1 ) Interest Expense — 3.5 — — 3.5 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) 3.5 (1.4 ) — 2.0 Income Tax (Expense) Credit (0.1 ) 1.3 (0.5 ) — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Ohio Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2016 , 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues 59.1 — — — — 59.1 Purchased Electricity for Resale (39.1 ) — — — — (39.1 ) Regulatory Assets/(Liabilities), Net (a) (2.8 ) — — — — (2.8 ) Interest Expense — 6.1 — — — 6.1 Amortization of Prior Service Cost (Credit) — — — (20.6 ) — (20.6 ) Amortization of Actuarial (Gains)/Losses — — — 28.0 — 28.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 17.2 6.1 — 7.4 — 30.7 Income Tax (Expense) Credit 6.0 2.2 — 2.6 — 10.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit — (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ — $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit — (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit — (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.5 ) — — — (0.5 ) Regulatory Assets/(Liabilities), Net (a) (2.2 ) — — — (2.2 ) Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.1 — 3.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.7 ) 1.2 (2.0 ) — (3.5 ) Income Tax (Expense) Credit (0.9 ) 0.4 (0.7 ) — (1.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.0 — — 2.0 Income Tax (Expense) Credit — 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) — 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ — $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 1.7 — — 1.7 Income Tax (Expense) Credit — 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.8 ) — — — (0.8 ) Regulatory Assets/(Liabilities), Net (a) (1.0 ) — — — (1.0 ) Interest Expense — 2.4 — — 2.4 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 1.1 — 1.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.8 ) 2.4 0.3 — 0.9 Income Tax (Expense) Credit (0.6 ) 0.8 0.1 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 4.3 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.9 ) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.9 ) (1.9 ) Income Tax (Expense) Credit — (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) (1.3 ) Balance in AOCI as of December 31, 2016 $ — $ 3.0 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (2.0 ) — — (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (2.0 ) — — (2.0 ) Income Tax (Expense) Credit — (0.7 ) — — (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.2 ) — — — (0.2 ) Interest Expense — (2.1 ) — — (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (2.1 ) — — (2.3 ) Income Tax (Expense) Credit (0.1 ) (0.7 ) — — (0.8 ) 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 December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2016 $ — $ 3.4 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — (0.1 ) Interest Expense — (1.1 ) (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (1.1 ) (1.2 ) Income Tax (Expense) Credit — (0.4 ) (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit — 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ — $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit — 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit — 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — — — (0.1 ) Interest Expense — 3.5 — — 3.5 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) 3.5 (1.4 ) — 2.0 Income Tax (Expense) Credit (0.1 ) 1.3 (0.5 ) — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Public Service Co Of Oklahoma [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2016 , 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues 59.1 — — — — 59.1 Purchased Electricity for Resale (39.1 ) — — — — (39.1 ) Regulatory Assets/(Liabilities), Net (a) (2.8 ) — — — — (2.8 ) Interest Expense — 6.1 — — — 6.1 Amortization of Prior Service Cost (Credit) — — — (20.6 ) — (20.6 ) Amortization of Actuarial (Gains)/Losses — — — 28.0 — 28.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 17.2 6.1 — 7.4 — 30.7 Income Tax (Expense) Credit 6.0 2.2 — 2.6 — 10.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit — (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ — $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit — (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit — (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.5 ) — — — (0.5 ) Regulatory Assets/(Liabilities), Net (a) (2.2 ) — — — (2.2 ) Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.1 — 3.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.7 ) 1.2 (2.0 ) — (3.5 ) Income Tax (Expense) Credit (0.9 ) 0.4 (0.7 ) — (1.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.0 — — 2.0 Income Tax (Expense) Credit — 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) — 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ — $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 1.7 — — 1.7 Income Tax (Expense) Credit — 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.8 ) — — — (0.8 ) Regulatory Assets/(Liabilities), Net (a) (1.0 ) — — — (1.0 ) Interest Expense — 2.4 — — 2.4 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 1.1 — 1.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.8 ) 2.4 0.3 — 0.9 Income Tax (Expense) Credit (0.6 ) 0.8 0.1 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 4.3 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.9 ) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.9 ) (1.9 ) Income Tax (Expense) Credit — (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) (1.3 ) Balance in AOCI as of December 31, 2016 $ — $ 3.0 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (2.0 ) — — (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (2.0 ) — — (2.0 ) Income Tax (Expense) Credit — (0.7 ) — — (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.2 ) — — — (0.2 ) Interest Expense — (2.1 ) — — (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (2.1 ) — — (2.3 ) Income Tax (Expense) Credit (0.1 ) (0.7 ) — — (0.8 ) 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 December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2016 $ — $ 3.4 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — (0.1 ) Interest Expense — (1.1 ) (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (1.1 ) (1.2 ) Income Tax (Expense) Credit — (0.4 ) (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit — 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ — $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit — 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit — 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — — — (0.1 ) Interest Expense — 3.5 — — 3.5 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) 3.5 (1.4 ) — 2.0 Income Tax (Expense) Credit (0.1 ) 1.3 (0.5 ) — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Southwestern Electric Power Co [Member]
Comprehensive Income	COMPREHENSIVE INCOME The disclosures in this note apply to all Registrants unless indicated otherwise. Presentation of Comprehensive Income The following tables provide the components of changes in AOCI and details of reclassifications from AOCI for the years ended December 31, 2016 , 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 8 for additional details. AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues 59.1 — — — — 59.1 Purchased Electricity for Resale (39.1 ) — — — — (39.1 ) Regulatory Assets/(Liabilities), Net (a) (2.8 ) — — — — (2.8 ) Interest Expense — 6.1 — — — 6.1 Amortization of Prior Service Cost (Credit) — — — (20.6 ) — (20.6 ) Amortization of Actuarial (Gains)/Losses — — — 28.0 — 28.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 17.2 6.1 — 7.4 — 30.7 Income Tax (Expense) Credit 6.0 2.2 — 2.6 — 10.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit — (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ — $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit — (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit — (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.5 ) — — — (0.5 ) Regulatory Assets/(Liabilities), Net (a) (2.2 ) — — — (2.2 ) Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.1 — 3.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.7 ) 1.2 (2.0 ) — (3.5 ) Income Tax (Expense) Credit (0.9 ) 0.4 (0.7 ) — (1.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.0 — — 2.0 Income Tax (Expense) Credit — 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) — 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ — $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 1.7 — — 1.7 Income Tax (Expense) Credit — 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.8 ) — — — (0.8 ) Regulatory Assets/(Liabilities), Net (a) (1.0 ) — — — (1.0 ) Interest Expense — 2.4 — — 2.4 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 1.1 — 1.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.8 ) 2.4 0.3 — 0.9 Income Tax (Expense) Credit (0.6 ) 0.8 0.1 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 4.3 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.9 ) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.9 ) (1.9 ) Income Tax (Expense) Credit — (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) (1.3 ) Balance in AOCI as of December 31, 2016 $ — $ 3.0 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (2.0 ) — — (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (2.0 ) — — (2.0 ) Income Tax (Expense) Credit — (0.7 ) — — (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.2 ) — — — (0.2 ) Interest Expense — (2.1 ) — — (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (2.1 ) — — (2.3 ) Income Tax (Expense) Credit (0.1 ) (0.7 ) — — (0.8 ) 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 December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2016 $ — $ 3.4 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — (0.1 ) Interest Expense — (1.1 ) (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (1.1 ) (1.2 ) Income Tax (Expense) Credit — (0.4 ) (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit — 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ — $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit — 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit — 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — — — (0.1 ) Interest Expense — 3.5 — — 3.5 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) 3.5 (1.4 ) — 2.0 Income Tax (Expense) Credit (0.1 ) 1.3 (0.5 ) — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Rate Matters

Rate Matters	12 Months Ended
	Dec. 31, 2016
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 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, the 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. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million , effective March 2017. As of December 31, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. 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 November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors. 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. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year 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. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case 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 Global Settlement In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits. The significant components of the Global Settlement include: Remands Related to the PIRR All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million . Remands Related to the RSR Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income. For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income: AEP (in millions) Fuel and Other Consumables Used for Electric Generation $ (19.0 ) Purchased Electricity for Resale (19.9 ) Other Operation (15.7 ) Depreciation and Amortization (42.1 ) Total Decrease in RSR Expenses $ (96.7 ) As of December 31, 2016 , OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million . Remands Related to the SEET As part of the Global Settlement, $20 million will be returned to customers over a 12 -month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings. Fuel Adjustment Clause Proceedings OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle. 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 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above. 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. See “Ohio Global Settlement” section above. 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 December 31, 2016 , OPCo’s net deferred capacity costs balance was $202 million , including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. 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. See “Ohio Global Settlement” section above. 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 “Ohio Global Settlement” section above and “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 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above. 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 November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps. 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 MWs 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 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 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 to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. 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. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART ® Phase II stipulation. In February 2017, the PUCO approved the gridSMART ® Phase II stipulation agreement. See “Ohio Global Settlement” section above. 2014 and 2015 SEET Filings 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 was not 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. 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. See “Ohio Global Settlement” section above. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. 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 statements 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 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above. 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” and “Ohio Global Settlement” sections above. 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
Appalachian Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 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, the 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. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million , effective March 2017. As of December 31, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. 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 November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors. 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. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year 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. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case 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 Global Settlement In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits. The significant components of the Global Settlement include: Remands Related to the PIRR All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million . Remands Related to the RSR Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income. For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income: AEP (in millions) Fuel and Other Consumables Used for Electric Generation $ (19.0 ) Purchased Electricity for Resale (19.9 ) Other Operation (15.7 ) Depreciation and Amortization (42.1 ) Total Decrease in RSR Expenses $ (96.7 ) As of December 31, 2016 , OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million . Remands Related to the SEET As part of the Global Settlement, $20 million will be returned to customers over a 12 -month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings. Fuel Adjustment Clause Proceedings OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle. 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 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above. 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. See “Ohio Global Settlement” section above. 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 December 31, 2016 , OPCo’s net deferred capacity costs balance was $202 million , including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. 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. See “Ohio Global Settlement” section above. 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 “Ohio Global Settlement” section above and “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 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above. 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 November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps. 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 MWs 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 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 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 to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. 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. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART ® Phase II stipulation. In February 2017, the PUCO approved the gridSMART ® Phase II stipulation agreement. See “Ohio Global Settlement” section above. 2014 and 2015 SEET Filings 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 was not 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. 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. See “Ohio Global Settlement” section above. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. 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 statements 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 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above. 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” and “Ohio Global Settlement” sections above. 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
Indiana Michigan Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 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, the 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. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million , effective March 2017. As of December 31, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. 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 November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors. 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. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year 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. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case 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 Global Settlement In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits. The significant components of the Global Settlement include: Remands Related to the PIRR All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million . Remands Related to the RSR Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income. For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income: AEP (in millions) Fuel and Other Consumables Used for Electric Generation $ (19.0 ) Purchased Electricity for Resale (19.9 ) Other Operation (15.7 ) Depreciation and Amortization (42.1 ) Total Decrease in RSR Expenses $ (96.7 ) As of December 31, 2016 , OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million . Remands Related to the SEET As part of the Global Settlement, $20 million will be returned to customers over a 12 -month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings. Fuel Adjustment Clause Proceedings OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle. 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 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above. 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. See “Ohio Global Settlement” section above. 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 December 31, 2016 , OPCo’s net deferred capacity costs balance was $202 million , including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. 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. See “Ohio Global Settlement” section above. 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 “Ohio Global Settlement” section above and “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 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above. 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 November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps. 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 MWs 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 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 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 to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. 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. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART ® Phase II stipulation. In February 2017, the PUCO approved the gridSMART ® Phase II stipulation agreement. See “Ohio Global Settlement” section above. 2014 and 2015 SEET Filings 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 was not 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. 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. See “Ohio Global Settlement” section above. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. 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 statements 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 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above. 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” and “Ohio Global Settlement” sections above. 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
Ohio Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 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, the 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. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million , effective March 2017. As of December 31, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. 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 November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors. 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. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year 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. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case 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 Global Settlement In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits. The significant components of the Global Settlement include: Remands Related to the PIRR All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million . Remands Related to the RSR Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income. For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income: AEP (in millions) Fuel and Other Consumables Used for Electric Generation $ (19.0 ) Purchased Electricity for Resale (19.9 ) Other Operation (15.7 ) Depreciation and Amortization (42.1 ) Total Decrease in RSR Expenses $ (96.7 ) As of December 31, 2016 , OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million . Remands Related to the SEET As part of the Global Settlement, $20 million will be returned to customers over a 12 -month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings. Fuel Adjustment Clause Proceedings OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle. 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 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above. 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. See “Ohio Global Settlement” section above. 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 December 31, 2016 , OPCo’s net deferred capacity costs balance was $202 million , including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. 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. See “Ohio Global Settlement” section above. 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 “Ohio Global Settlement” section above and “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 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above. 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 November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps. 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 MWs 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 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 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 to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. 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. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART ® Phase II stipulation. In February 2017, the PUCO approved the gridSMART ® Phase II stipulation agreement. See “Ohio Global Settlement” section above. 2014 and 2015 SEET Filings 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 was not 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. 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. See “Ohio Global Settlement” section above. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. 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 statements 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 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above. 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” and “Ohio Global Settlement” sections above. 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
Public Service Co Of Oklahoma [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 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, the 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. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million , effective March 2017. As of December 31, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. 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 November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors. 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. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year 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. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case 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 Global Settlement In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits. The significant components of the Global Settlement include: Remands Related to the PIRR All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million . Remands Related to the RSR Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income. For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income: AEP (in millions) Fuel and Other Consumables Used for Electric Generation $ (19.0 ) Purchased Electricity for Resale (19.9 ) Other Operation (15.7 ) Depreciation and Amortization (42.1 ) Total Decrease in RSR Expenses $ (96.7 ) As of December 31, 2016 , OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million . Remands Related to the SEET As part of the Global Settlement, $20 million will be returned to customers over a 12 -month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings. Fuel Adjustment Clause Proceedings OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle. 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 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above. 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. See “Ohio Global Settlement” section above. 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 December 31, 2016 , OPCo’s net deferred capacity costs balance was $202 million , including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. 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. See “Ohio Global Settlement” section above. 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 “Ohio Global Settlement” section above and “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 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above. 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 November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps. 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 MWs 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 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 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 to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. 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. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART ® Phase II stipulation. In February 2017, the PUCO approved the gridSMART ® Phase II stipulation agreement. See “Ohio Global Settlement” section above. 2014 and 2015 SEET Filings 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 was not 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. 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. See “Ohio Global Settlement” section above. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. 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 statements 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 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above. 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” and “Ohio Global Settlement” sections above. 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
Southwestern Electric Power Co [Member]
Rate Matters	RATE MATTERS The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. Rate matters can have a material impact on net income, cash flows and possibly financial condition. The Registrants’ recent significant rate orders and pending rate filings are addressed in this note. APCo and WPCo Rate Matters (Applies to AEP and APCo) 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, the 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. During a 2015 open meeting at the PUCT, ETT committed to file a base rate case by February 2017. In January 2017, the PUCT approved ETT’s request to suspend the base rate case filing and decrease ETT’s annual revenue requirement by $46 million , effective March 2017. As of December 31, 2016 , AEP’s share of ETT’s cumulative revenues, subject to review, is estimated to be $591 million based upon interim rate increases received from 2009 through 2016. 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 November 2016, the IURC issued an order that approved an amended settlement agreement between I&M and certain intervenors. 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. Rockport Plant, Unit 2 Selective Catalytic Reduction (SCR) In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) to install SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NO x from Rockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost of the SCR project is $274 million , excluding AFUDC, to be shared equally between I&M and AEGCo. The filing included a request for authorization for I&M to defer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC), depreciation over a 10-year 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. In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCC recommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due to retirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other parties recommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed to be recovered in the rider and limitations on other costs related to legal issues involving the Rockport lease. A hearing at the IURC is scheduled for March 2017. KGPCo Rate Matters (Applies to AEP) Kingsport Base Rate Case 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 Global Settlement In February 2017, the PUCO approved a settlement agreement (Global Settlement) filed by OPCo in December 2016. The parties to the Global Settlement include OPCo, the PUCO staff and various intervenors. The Global Settlement resolves all remaining open issues on remand from the Ohio Supreme Court in OPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings, including issues related to carrying charges on the PIRR and issues related to the RSR capacity charges. It also resolves all open issues in OPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment Clause Audits. The significant components of the Global Settlement include: Remands Related to the PIRR All applicable parties participating in this settlement will withdraw their pending applications for rehearing of the PUCO order that allowed for the reinstatement of the equity portion of the WACC rate on previously deferred fuel balances. As part of the Global Settlement, the PIRR rate to be collected from customers through December 2018 will be reduced by $97 million . Remands Related to the RSR Beginning January 2017, OPCo will be entitled to collect $388 million in RSR revenues over a total of 30 months, subject to true up at the end of the collection period in June 2019. Current RSR rates will continue until the new RSR rates are approved. The Global Settlement resolves the issues related to the non-deferral portion of RSR collections and the impact of the appropriate energy credit on capacity charges. In December 2016, OPCo recorded an increase in Regulatory Assets on the balance sheets for the deferral of $83 million in RSR capacity costs and $14 million in related debt carrying charges with a corresponding decrease in expense in Generation Deferrals and an increase in Carrying Costs Income, respectively, on the statements of income. For the year ended December 31, 2016, AEP recorded approximately $97 million in RSR capacity deferrals and related carrying charges to the following line items on the statements of income: AEP (in millions) Fuel and Other Consumables Used for Electric Generation $ (19.0 ) Purchased Electricity for Resale (19.9 ) Other Operation (15.7 ) Depreciation and Amortization (42.1 ) Total Decrease in RSR Expenses $ (96.7 ) As of December 31, 2016 , OPCo’s total RSR under-recovery balance, including carrying charges, was $299 million . Remands Related to the SEET As part of the Global Settlement, $20 million will be returned to customers over a 12 -month period commencing within 45 days of the final PUCO order adopting the Global Settlement. The Global Settlement states that this obligation has no precedential effect on OPCo’s SEET methodology. In addition, the parties agreed that earnings were not significantly excessive in 2015. In December 2016, OPCo accrued $20 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the issues related to the 2014 and 2015 SEET proceedings. Fuel Adjustment Clause Proceedings OPCo will refund $100 million paid by SSO customers from August 2012 - May 2015 related to OVEC and Lawrenceburg purchases. In December 2016, OPCo accrued $100 million in Other Current Liabilities on the balance sheets with a corresponding decrease in Electricity, Transmission and Distribution revenues (Transmission and Distribution Utilities for AEP) on the statements of income. The Global Settlement resolves the claimed recovery of fixed fuel costs through both the FAC and the approved capacity charges. This refund will be a one-time credit that will be applied the earlier of either 45 days after the final non-appealable order from the PUCO adopting the Global Settlement, or the December 2017 billing cycle. 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 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to this issue. See “Ohio Global Settlement” section above. 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. See “Ohio Global Settlement” section above. 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 December 31, 2016 , OPCo’s net deferred capacity costs balance was $202 million , including debt carrying costs, and was recorded in Regulatory Assets on the balance sheets. 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. See “Ohio Global Settlement” section above. 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 “Ohio Global Settlement” section above and “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 2014, the PUCO denied all rehearing requests, 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, and 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. See “2012 and 2013 Fuel Adjustment Clause Audits” section below. 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, and due to the interrelated nature of the two Supreme Court of Ohio opinions that directly relate to OPCo’s deferred capacity costs, 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. 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. In December 2016, OPCo filed a Global Settlement with the PUCO related to these issues. See “Ohio Global Settlement” section above. 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 November 2016, the PUCO issued an additional order on rehearing that approved the DIR caps with additional amendments and denied the remaining requests for rehearing. In January 2017, the PUCO granted intervenors requests for rehearing that oppose the PPA rider as well as the amended DIR caps. 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 MWs 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 MWs and a wind energy project(s) of at least 500 MWs, with 100% of all output to be received by OPCo. AEP affiliates could own up to 50% of these solar and wind projects. In December 2016, in accordance with the stipulation agreement, OPCo filed a carbon reduction plan that focused on fuel diversification and carbon emission reductions. In April 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 to recover the net margin after sales through PJM and 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 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. In November 2016, the PUCO issued an order on rehearing that approved recovery of the OVEC-related net margin incurred from June 2016 through the term of the PPA rider and the modification to reduce the customer credits to $15 million as requested by OPCo. The PUCO rejected OPCo’s request to eliminate both the 5% rate impact cap and the inclusion of the capacity performance penalties within the PPA rider. In January 2017, the PUCO granted, for further consideration, intervenors additional applications for rehearing that included arguments that opposed the OVEC-only PPA and stated that the stipulation agreement approved in March 2016 does not provide customers with rate stability. OPCo has the option to exercise its right to withdraw from the PPA stipulation if the PUCO makes unacceptable modifications to the stipulation, including modifications as part of the pending rehearing. Consistent with the terms of the modified and approved stipulation agreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application and supporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPA rider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders, including a Distribution Technology Rider and a Renewable Resource Rider. 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. As a part of the December 2016 Global Settlement, OCC agreed to no longer contest the gridSMART ® Phase II stipulation. In February 2017, the PUCO approved the gridSMART ® Phase II stipulation agreement. See “Ohio Global Settlement” section above. 2014 and 2015 SEET Filings 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 was not 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. 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. See “Ohio Global Settlement” section above. 2016 SEET Filing OPCo expects to submit its 2016 SEET filing in the second quarter of 2017. OPCo’s 2016 SEET provision was determined by excluding the gain on the deferral of RSR costs related to the Global Settlement. In addition, refunds to customers included in the Global Settlement relating to the SEET remands and fuel adjustment clause proceedings were excluded from the determination of the 2016 SEET provision. Management believes its financial statements adequately address the impact of 2016 SEET requirements. If the PUCO adopts a different 2016 SEET methodology, it could reduce future net income and cash flows and impact financial condition. 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 statements 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 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. See “Ohio Global Settlement” section above. 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” and “Ohio Global Settlement” sections above. 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

Effects of Regulation

Effects of Regulation	12 Months Ended
	Dec. 31, 2016
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2016 2015 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 61.4 $ 38.9 1 year Under-recovered Fuel Costs - does not earn a return 95.2 76.3 1 year Total Current Regulatory Assets $ 156.6 $ 115.2 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 159.9 $ — Ohio Capacity Deferral 96.7 — Storm Related Costs 25.1 24.2 Plant Retirement Costs - Materials and Supplies 9.1 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.3 — Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 — Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 59.8 Storm Related Costs 25.9 18.2 Environmental Control Projects 24.1 — Cook Plant Turbine 12.8 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 29.1 22.0 Total Regulatory Assets Pending Final Regulatory Approval (b) 450.1 167.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 550.6 539.3 28 years Ohio Phase-In Recovery Rider 218.9 304.5 2 years Ohio Capacity Deferral 201.9 358.7 2 years Meter Replacement Costs 99.9 90.4 11 years Ohio Distribution Decoupling 41.8 37.5 2 years Advanced Metering System 20.9 3.6 4 years Basic Transmission Cost Rider 19.9 — 2 years West Virginia Delayed Customer Billing 19.5 — 2 years Asset Removal Costs 18.7 38.1 (a) Mitchell Plant Transfer 18.5 19.3 24 years Plant Retirement Costs - Asset Retirement Obligation Costs 18.3 7.6 24 years Storm Related Costs 15.3 8.8 3 years Red Rock Generating Facility 9.1 9.3 40 years Ohio Transmission Cost Recovery Rider — 12.3 Other Regulatory Assets Approved for Recovery 27.6 25.5 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (c) 1,575.0 1,385.3 62 years Pension and OPEB Funded Status 1,516.2 1,410.5 12 years Unamortized Loss on Reacquired Debt 137.8 148.7 29 years Unrealized Loss on Forward Commitments 119.1 10.7 16 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Storm Related Costs 58.7 94.6 4 years Peak Demand Reduction/Energy Efficiency 49.9 33.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 48.9 58.0 24 years Postemployment Benefits 39.1 42.6 5 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Medicare Subsidy 37.2 41.8 8 years Vegetation Management 31.4 36.9 5 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years OVEC Purchased Power 22.1 — 2 years United Mine Workers of America Pension Withdrawal 20.2 14.4 6 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year SPP Base Plan Fees 10.7 — 2 years Carbon Capture and Storage Product Validation Facility 9.1 11.7 4 years IGCC Pre-Construction Costs 8.6 10.9 24 years Transmission Cost Recovery Factor 5.3 9.9 1 year Distribution Investment Rider 2.0 12.3 2 years Other Regulatory Assets Approved for Recovery 52.5 77.8 various Total Regulatory Assets Approved for Recovery 5,175.4 4,972.4 Total Noncurrent Regulatory Assets $ 5,625.5 $ 5,140.3 (a) As a regulated entity, removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. As of December 31, 2016 , KPCo’s accumulated actual removal cost incurred exceeded accumulated removal cost accrued, creating an asset balance. As a result, the balance was reclassified to a regulatory asset. Within the next two years, KPCo’s removal costs accrued are expected to exceed removal costs incurred resulting in a regulatory liability. (b) As of December 31, 2016, APCo has deferred a total of $91 million as charges to accumulated depreciation related to certain plant retirements in 2015. APCo intends to address the need for depreciation rate increases in a subsequent base rate cases. (c) Includes $320 million and $288 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. AEP December 31, Remaining 2016 2015 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 3.8 $ 84.8 1 year Over-recovered Fuel Costs - does not pay a return 4.2 29.1 1 year Total Current Regulatory Liabilities $ 8.0 $ 113.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.8 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.8 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) 2,627.5 2,656.5 (b) Advanced Metering Infrastructure Surcharge 17.0 21.2 4 years Louisiana Refundable Construction Financing Costs 16.2 37.4 2 years Deferred Investment Tax Credits 12.6 14.7 42 years Excess Earnings 10.0 10.6 37 years Other Regulatory Liabilities Approved for Payment 1.6 20.5 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Deferred Investment Tax Credits 132.9 113.3 46 years Spent Nuclear Fuel 44.2 43.4 (c) Transition Charges 40.5 46.5 11 years Peak Demand Reduction/Energy Efficiency 34.0 5.3 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Advanced Metering Costs 11.5 11.4 1 year Unrealized Gain on Forward Commitments 6.2 33.8 2 years Deferred Wind Power Costs 2.1 11.8 1 year Other Regulatory Liabilities Approved for Payment 29.4 24.4 various Total Regulatory Liabilities Approved for Payment 3,750.5 3,695.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,751.3 $ 3,736.1 (a) As of December 31, 2016, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 6.2 $ 27.3 1 year Under-recovered Fuel Costs - does not earn a return 62.2 59.6 1 year Total Current Regulatory Assets $ 68.4 $ 86.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 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 (a) 39.3 57.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.4 86.5 27 years West Virginia Delayed Customer Billing 18.1 — 2 years Storm Related Costs - Virginia 4.6 8.8 2 years RTO Formation/Integration Costs 1.6 2.1 3 years Other Regulatory Assets Approved for Recovery 0.6 — various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (b) 463.5 441.7 26 years Pension and OPEB Funded Status 221.4 217.6 12 years Unamortized Loss on Reacquired Debt 97.2 101.5 29 years Storm Related Costs - West Virginia 47.8 63.5 4 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Vegetation Management Program - West Virginia 31.4 31.2 5 years Peak Demand Reduction/Energy Efficiency 19.2 3.5 4 years Postemployment Benefits 17.4 19.6 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 9.1 11.7 4 years IGCC Pre-Construction Costs - West Virginia, FERC 7.4 9.6 4 years Virginia Generation Rate Adjustment Clause 6.5 5.2 2 years Medicare Subsidy - West Virginia, FERC 4.7 5.3 8 years Uncollected Accounts - West Virginia 2.7 3.5 4 years Deferred Restructuring Costs - West Virginia 2.5 4.5 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.0 1.2 6 years Asset Retirement Obligation 0.6 2.4 1 year Transmission Agreement Phase-In - West Virginia — 1.7 Other Regulatory Assets Approved for Recovery 0.4 1.2 various Total Regulatory Assets Approved for Recovery 1,081.8 1,096.9 Total Noncurrent Regulatory Assets $ 1,121.1 $ 1,154.2 (a) As of December 31, 2016, APCo has also deferred $91 million as a charge to accumulated depreciation related to the net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements and not abandonments. APCo intends to address the need for an increase in its Virginia depreciation rates in March 2020, as part of its 2018-2019 Virginia biennial filing. (b) Includes $64 million and $59 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 616.9 $ 612.9 (a) Deferred Investment Tax Credits 0.9 1.0 42 years Regulatory Liabilities Currently Not Paying a Return Consumer Rate Relief - West Virginia 5.1 2.9 1 year Deferred Wind Power Costs - Virginia 2.1 11.8 1 year Energy Efficiency Rate Adjustment Clause - Virginia 1.5 — 2 years Unrealized Gain on Forward Commitments 1.3 8.4 2 years Other Regulatory Liabilities Approved for Payment — 0.1 various Total Regulatory Liabilities Approved for Payment 627.8 637.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 627.8 $ 637.1 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 13.0 $ 7.5 1 year Under-recovered Fuel Costs - does not earn a return 13.1 4.1 1 year Total Current Regulatory Assets $ 26.1 $ 11.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ — $ 11.6 Regulatory Assets Currently Not Earning a Return Cook Uprate Project 36.3 — Cook Plant Turbine 12.8 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 8.1 4.2 Rockport Plant Dry Sorbent Injection System - Indiana 6.6 2.8 Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana — 27.1 Stranded Costs on Abandoned Plants — 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.9 — Total Regulatory Assets Pending Final Regulatory Approval 64.7 59.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 252.8 260.3 28 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.3 6.6 22 years RTO Formation/Integration Costs 1.2 1.5 3 years Other Regulatory Assets Approved for Recovery 1.3 1.0 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (a) 302.6 246.8 32 years Pension and OPEB Funded Status 141.9 126.4 12 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years Postemployment Benefits 11.4 10.7 5 years Unamortized Loss on Reacquired Debt 10.7 12.0 16 years Medicare Subsidy 8.2 9.2 8 years Litigation Settlement - Indiana 7.6 8.6 9 years River Transportation Division Expenses 3.7 — 1 year Peak Demand Reduction/Energy Efficiency 3.6 10.6 2 years Capacity Costs - Indiana 0.4 7.5 1 year Unrealized Loss on Forward Commitments 0.1 3.2 2 years PJM Expense - Indiana — 4.1 Storm Related Costs - Indiana — 1.8 Other Regulatory Assets Approved for Recovery 0.6 1.1 various Total Regulatory Assets Approved for Recovery 851.9 745.0 Total Noncurrent Regulatory Assets $ 916.6 $ 804.3 (a) Includes $74 million and $69 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rate s. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 0.3 Total Current Regulatory Liabilities $ — $ 0.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) $ 236.5 $ 350.6 (b) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Spent Nuclear Fuel 44.2 43.4 (c) Deferred Investment Tax Credits 38.8 35.0 20 years Deferred Cook Plant Life Cycle Management Project Costs - Indiana 4.6 — 3 years PJM Expense - Indiana 4.2 — 2 years Unrealized Gain on Forward Commitments 2.4 7.1 2 years Rockport Plant Dry Sorbent Injection 1.7 0.4 2 years Storm Related Costs - Indiana 1.2 — 1 year River Transportation Division Expenses — 1.9 Other Regulatory Liabilities Approved for Payment 0.7 1.3 various Total Regulatory Liabilities Approved for Payment 1,065.5 1,076.2 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,065.5 $ 1,076.2 (a) As of December 31, 2016, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ 96.7 $ — Regulatory Assets Currently Not Earning a Return gridSMART ® Costs 4.1 1.3 Total Regulatory Assets Pending Final Regulatory Approval 100.8 1.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Phase-In Recovery Rider 218.9 304.5 2 years Capacity Deferral 201.9 358.7 2 years Distribution Decoupling 41.8 37.5 2 years Basic Transmission Cost Rider 19.9 — 2 years RTO Formation/Integration Costs 2.5 3.1 3 years Economic Development Rider 1.7 — 2 years Transmission Cost Recovery Rider — 12.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 225.2 219.4 12 years Income Taxes, Net (a) 126.4 129.0 28 years Unrealized Loss on Forward Commitments 118.6 — 16 years OVEC Purchased Power 22.1 — 2 years Unamortized Loss on Reacquired Debt 9.1 10.4 22 years Medicare Subsidy 8.3 9.3 8 years Postemployment Benefits 6.8 7.3 5 years Distribution Investment Rider 2.0 12.3 2 years Partnership with Ohio Contribution 1.4 2.4 2 years gridSMART ® Costs — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.0 various Total Regulatory Assets Approved for Recovery 1,006.7 1,111.7 Total Noncurrent Regulatory Assets $ 1,107.5 $ 1,113.0 (a) Includes $76 million and $82 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. OPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 4.2 $ 27.6 1 year Total Current Regulatory Liabilities $ 4.2 $ 27.6 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 432.4 422.3 (a) Basic Transmission Cost Rider 0.3 4.9 2 years Economic Development Rider — 5.0 Regulatory Liabilities Currently Not Paying a Return Peak Demand Reduction/Energy Efficiency 29.0 1.5 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Storm Related Costs 5.3 1.3 2 years Deferred Asset Phase-In Rider 4.5 5.1 4 years Unrealized Gain on Forward Commitments — 15.3 Regulatory Settlement — 9.0 Other Regulatory Liabilities Approved for Payment 0.9 1.0 various Total Regulatory Liabilities Approved for Payment 506.0 473.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 506.2 $ 514.2 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 33.8 $ — 1 year Total Current Regulatory Assets $ 33.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 84.5 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.5 — Regulatory Assets Currently Not Earning a Return Storm Related Costs 20.0 12.3 Environmental Control Projects 13.1 — Other Regulatory Assets Pending Final Regulatory Approval — 1.1 Total Regulatory Assets Pending Final Regulatory Approval 118.1 13.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 50.1 35.8 8 years Storm Related Costs 10.8 — 3 years Red Rock Generating Facility 9.1 9.3 40 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 98.1 95.1 12 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year Storm Related Costs — 15.4 SPP Base Plan Fees 10.7 — 2 years Peak Demand Reduction/Energy Efficiency 10.3 11.8 2 years Income Taxes, Net 9.3 6.1 33 years Unamortized Loss on Reacquired Debt 5.8 6.8 16 years Medicare Subsidy 3.9 4.4 8 years Rate Case Expenses 1.4 1.2 1 year Vegetation Management — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.1 various Total Regulatory Assets Approved for Recovery 222.1 201.4 Total Noncurrent Regulatory Assets $ 340.2 $ 214.8 PSO December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 76.1 Total Current Regulatory Liabilities $ — $ 76.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 279.3 $ 275.5 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 48.0 46.3 38 years Advanced Metering Costs 11.5 11.4 1 year Base Plan Funding Costs — 1.3 Other Regulatory Liabilities Approved for Payment 0.9 0.6 various Total Regulatory Liabilities Approved for Payment 339.7 335.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 339.7 $ 335.1 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 8.4 $ 4.1 1 year Total Current Regulatory Assets $ 8.4 $ 4.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.8 — Regulatory Assets Currently Not Earning a Return Environmental Controls Projects 11.0 — Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.7 1.7 Rate Case Expense - Texas 1.0 0.3 Other Regulatory Assets Pending Final Regulatory Approval 1.9 0.8 Total Regulatory Assets Pending Final Regulatory Approval 95.9 5.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 1.3 0.2 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 314.2 271.9 34 years Pension and OPEB Funded Status 119.8 108.9 12 years Unamortized Loss on Reacquired Debt 5.4 6.0 27 years Medicare Subsidy 4.3 4.8 8 years Rate Case Expense - Texas 4.2 6.8 2 years Peak Demand Reduction/Energy Efficiency 3.0 1.0 2 years Deferred Restructuring Costs - Louisiana 1.9 3.5 2 years Unrealized Loss on Forward Commitments 0.3 5.5 1 year Other Regulatory Assets Approved for Recovery 0.9 1.3 various Total Regulatory Assets Approved for Recovery 455.3 409.9 Total Noncurrent Regulatory Assets $ 551.2 $ 415.8 SWEPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 3.8 $ 8.4 1 year Total Current Regulatory Liabilities $ 3.8 $ 8.4 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 409.7 $ 396.8 (a) Refundable Construction Financing Costs - Louisiana 16.2 37.4 2 years Excess Earnings - Texas 2.7 2.7 37 years Generation Recovery Rider Costs - Arkansas 1.2 1.5 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 7.3 8.5 14 years Other Regulatory Liabilities Approved for Payment 1.8 1.9 various Total Regulatory Liabilities Approved for Payment 438.9 448.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 438.9 $ 448.8 (a) Relieved as removal costs are incurred.
Appalachian Power Co [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2016 2015 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 61.4 $ 38.9 1 year Under-recovered Fuel Costs - does not earn a return 95.2 76.3 1 year Total Current Regulatory Assets $ 156.6 $ 115.2 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 159.9 $ — Ohio Capacity Deferral 96.7 — Storm Related Costs 25.1 24.2 Plant Retirement Costs - Materials and Supplies 9.1 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.3 — Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 — Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 59.8 Storm Related Costs 25.9 18.2 Environmental Control Projects 24.1 — Cook Plant Turbine 12.8 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 29.1 22.0 Total Regulatory Assets Pending Final Regulatory Approval (b) 450.1 167.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 550.6 539.3 28 years Ohio Phase-In Recovery Rider 218.9 304.5 2 years Ohio Capacity Deferral 201.9 358.7 2 years Meter Replacement Costs 99.9 90.4 11 years Ohio Distribution Decoupling 41.8 37.5 2 years Advanced Metering System 20.9 3.6 4 years Basic Transmission Cost Rider 19.9 — 2 years West Virginia Delayed Customer Billing 19.5 — 2 years Asset Removal Costs 18.7 38.1 (a) Mitchell Plant Transfer 18.5 19.3 24 years Plant Retirement Costs - Asset Retirement Obligation Costs 18.3 7.6 24 years Storm Related Costs 15.3 8.8 3 years Red Rock Generating Facility 9.1 9.3 40 years Ohio Transmission Cost Recovery Rider — 12.3 Other Regulatory Assets Approved for Recovery 27.6 25.5 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (c) 1,575.0 1,385.3 62 years Pension and OPEB Funded Status 1,516.2 1,410.5 12 years Unamortized Loss on Reacquired Debt 137.8 148.7 29 years Unrealized Loss on Forward Commitments 119.1 10.7 16 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Storm Related Costs 58.7 94.6 4 years Peak Demand Reduction/Energy Efficiency 49.9 33.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 48.9 58.0 24 years Postemployment Benefits 39.1 42.6 5 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Medicare Subsidy 37.2 41.8 8 years Vegetation Management 31.4 36.9 5 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years OVEC Purchased Power 22.1 — 2 years United Mine Workers of America Pension Withdrawal 20.2 14.4 6 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year SPP Base Plan Fees 10.7 — 2 years Carbon Capture and Storage Product Validation Facility 9.1 11.7 4 years IGCC Pre-Construction Costs 8.6 10.9 24 years Transmission Cost Recovery Factor 5.3 9.9 1 year Distribution Investment Rider 2.0 12.3 2 years Other Regulatory Assets Approved for Recovery 52.5 77.8 various Total Regulatory Assets Approved for Recovery 5,175.4 4,972.4 Total Noncurrent Regulatory Assets $ 5,625.5 $ 5,140.3 (a) As a regulated entity, removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. As of December 31, 2016 , KPCo’s accumulated actual removal cost incurred exceeded accumulated removal cost accrued, creating an asset balance. As a result, the balance was reclassified to a regulatory asset. Within the next two years, KPCo’s removal costs accrued are expected to exceed removal costs incurred resulting in a regulatory liability. (b) As of December 31, 2016, APCo has deferred a total of $91 million as charges to accumulated depreciation related to certain plant retirements in 2015. APCo intends to address the need for depreciation rate increases in a subsequent base rate cases. (c) Includes $320 million and $288 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. AEP December 31, Remaining 2016 2015 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 3.8 $ 84.8 1 year Over-recovered Fuel Costs - does not pay a return 4.2 29.1 1 year Total Current Regulatory Liabilities $ 8.0 $ 113.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.8 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.8 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) 2,627.5 2,656.5 (b) Advanced Metering Infrastructure Surcharge 17.0 21.2 4 years Louisiana Refundable Construction Financing Costs 16.2 37.4 2 years Deferred Investment Tax Credits 12.6 14.7 42 years Excess Earnings 10.0 10.6 37 years Other Regulatory Liabilities Approved for Payment 1.6 20.5 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Deferred Investment Tax Credits 132.9 113.3 46 years Spent Nuclear Fuel 44.2 43.4 (c) Transition Charges 40.5 46.5 11 years Peak Demand Reduction/Energy Efficiency 34.0 5.3 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Advanced Metering Costs 11.5 11.4 1 year Unrealized Gain on Forward Commitments 6.2 33.8 2 years Deferred Wind Power Costs 2.1 11.8 1 year Other Regulatory Liabilities Approved for Payment 29.4 24.4 various Total Regulatory Liabilities Approved for Payment 3,750.5 3,695.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,751.3 $ 3,736.1 (a) As of December 31, 2016, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 6.2 $ 27.3 1 year Under-recovered Fuel Costs - does not earn a return 62.2 59.6 1 year Total Current Regulatory Assets $ 68.4 $ 86.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 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 (a) 39.3 57.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.4 86.5 27 years West Virginia Delayed Customer Billing 18.1 — 2 years Storm Related Costs - Virginia 4.6 8.8 2 years RTO Formation/Integration Costs 1.6 2.1 3 years Other Regulatory Assets Approved for Recovery 0.6 — various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (b) 463.5 441.7 26 years Pension and OPEB Funded Status 221.4 217.6 12 years Unamortized Loss on Reacquired Debt 97.2 101.5 29 years Storm Related Costs - West Virginia 47.8 63.5 4 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Vegetation Management Program - West Virginia 31.4 31.2 5 years Peak Demand Reduction/Energy Efficiency 19.2 3.5 4 years Postemployment Benefits 17.4 19.6 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 9.1 11.7 4 years IGCC Pre-Construction Costs - West Virginia, FERC 7.4 9.6 4 years Virginia Generation Rate Adjustment Clause 6.5 5.2 2 years Medicare Subsidy - West Virginia, FERC 4.7 5.3 8 years Uncollected Accounts - West Virginia 2.7 3.5 4 years Deferred Restructuring Costs - West Virginia 2.5 4.5 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.0 1.2 6 years Asset Retirement Obligation 0.6 2.4 1 year Transmission Agreement Phase-In - West Virginia — 1.7 Other Regulatory Assets Approved for Recovery 0.4 1.2 various Total Regulatory Assets Approved for Recovery 1,081.8 1,096.9 Total Noncurrent Regulatory Assets $ 1,121.1 $ 1,154.2 (a) As of December 31, 2016, APCo has also deferred $91 million as a charge to accumulated depreciation related to the net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements and not abandonments. APCo intends to address the need for an increase in its Virginia depreciation rates in March 2020, as part of its 2018-2019 Virginia biennial filing. (b) Includes $64 million and $59 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 616.9 $ 612.9 (a) Deferred Investment Tax Credits 0.9 1.0 42 years Regulatory Liabilities Currently Not Paying a Return Consumer Rate Relief - West Virginia 5.1 2.9 1 year Deferred Wind Power Costs - Virginia 2.1 11.8 1 year Energy Efficiency Rate Adjustment Clause - Virginia 1.5 — 2 years Unrealized Gain on Forward Commitments 1.3 8.4 2 years Other Regulatory Liabilities Approved for Payment — 0.1 various Total Regulatory Liabilities Approved for Payment 627.8 637.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 627.8 $ 637.1 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 13.0 $ 7.5 1 year Under-recovered Fuel Costs - does not earn a return 13.1 4.1 1 year Total Current Regulatory Assets $ 26.1 $ 11.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ — $ 11.6 Regulatory Assets Currently Not Earning a Return Cook Uprate Project 36.3 — Cook Plant Turbine 12.8 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 8.1 4.2 Rockport Plant Dry Sorbent Injection System - Indiana 6.6 2.8 Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana — 27.1 Stranded Costs on Abandoned Plants — 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.9 — Total Regulatory Assets Pending Final Regulatory Approval 64.7 59.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 252.8 260.3 28 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.3 6.6 22 years RTO Formation/Integration Costs 1.2 1.5 3 years Other Regulatory Assets Approved for Recovery 1.3 1.0 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (a) 302.6 246.8 32 years Pension and OPEB Funded Status 141.9 126.4 12 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years Postemployment Benefits 11.4 10.7 5 years Unamortized Loss on Reacquired Debt 10.7 12.0 16 years Medicare Subsidy 8.2 9.2 8 years Litigation Settlement - Indiana 7.6 8.6 9 years River Transportation Division Expenses 3.7 — 1 year Peak Demand Reduction/Energy Efficiency 3.6 10.6 2 years Capacity Costs - Indiana 0.4 7.5 1 year Unrealized Loss on Forward Commitments 0.1 3.2 2 years PJM Expense - Indiana — 4.1 Storm Related Costs - Indiana — 1.8 Other Regulatory Assets Approved for Recovery 0.6 1.1 various Total Regulatory Assets Approved for Recovery 851.9 745.0 Total Noncurrent Regulatory Assets $ 916.6 $ 804.3 (a) Includes $74 million and $69 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rate s. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 0.3 Total Current Regulatory Liabilities $ — $ 0.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) $ 236.5 $ 350.6 (b) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Spent Nuclear Fuel 44.2 43.4 (c) Deferred Investment Tax Credits 38.8 35.0 20 years Deferred Cook Plant Life Cycle Management Project Costs - Indiana 4.6 — 3 years PJM Expense - Indiana 4.2 — 2 years Unrealized Gain on Forward Commitments 2.4 7.1 2 years Rockport Plant Dry Sorbent Injection 1.7 0.4 2 years Storm Related Costs - Indiana 1.2 — 1 year River Transportation Division Expenses — 1.9 Other Regulatory Liabilities Approved for Payment 0.7 1.3 various Total Regulatory Liabilities Approved for Payment 1,065.5 1,076.2 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,065.5 $ 1,076.2 (a) As of December 31, 2016, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ 96.7 $ — Regulatory Assets Currently Not Earning a Return gridSMART ® Costs 4.1 1.3 Total Regulatory Assets Pending Final Regulatory Approval 100.8 1.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Phase-In Recovery Rider 218.9 304.5 2 years Capacity Deferral 201.9 358.7 2 years Distribution Decoupling 41.8 37.5 2 years Basic Transmission Cost Rider 19.9 — 2 years RTO Formation/Integration Costs 2.5 3.1 3 years Economic Development Rider 1.7 — 2 years Transmission Cost Recovery Rider — 12.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 225.2 219.4 12 years Income Taxes, Net (a) 126.4 129.0 28 years Unrealized Loss on Forward Commitments 118.6 — 16 years OVEC Purchased Power 22.1 — 2 years Unamortized Loss on Reacquired Debt 9.1 10.4 22 years Medicare Subsidy 8.3 9.3 8 years Postemployment Benefits 6.8 7.3 5 years Distribution Investment Rider 2.0 12.3 2 years Partnership with Ohio Contribution 1.4 2.4 2 years gridSMART ® Costs — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.0 various Total Regulatory Assets Approved for Recovery 1,006.7 1,111.7 Total Noncurrent Regulatory Assets $ 1,107.5 $ 1,113.0 (a) Includes $76 million and $82 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. OPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 4.2 $ 27.6 1 year Total Current Regulatory Liabilities $ 4.2 $ 27.6 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 432.4 422.3 (a) Basic Transmission Cost Rider 0.3 4.9 2 years Economic Development Rider — 5.0 Regulatory Liabilities Currently Not Paying a Return Peak Demand Reduction/Energy Efficiency 29.0 1.5 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Storm Related Costs 5.3 1.3 2 years Deferred Asset Phase-In Rider 4.5 5.1 4 years Unrealized Gain on Forward Commitments — 15.3 Regulatory Settlement — 9.0 Other Regulatory Liabilities Approved for Payment 0.9 1.0 various Total Regulatory Liabilities Approved for Payment 506.0 473.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 506.2 $ 514.2 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 33.8 $ — 1 year Total Current Regulatory Assets $ 33.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 84.5 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.5 — Regulatory Assets Currently Not Earning a Return Storm Related Costs 20.0 12.3 Environmental Control Projects 13.1 — Other Regulatory Assets Pending Final Regulatory Approval — 1.1 Total Regulatory Assets Pending Final Regulatory Approval 118.1 13.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 50.1 35.8 8 years Storm Related Costs 10.8 — 3 years Red Rock Generating Facility 9.1 9.3 40 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 98.1 95.1 12 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year Storm Related Costs — 15.4 SPP Base Plan Fees 10.7 — 2 years Peak Demand Reduction/Energy Efficiency 10.3 11.8 2 years Income Taxes, Net 9.3 6.1 33 years Unamortized Loss on Reacquired Debt 5.8 6.8 16 years Medicare Subsidy 3.9 4.4 8 years Rate Case Expenses 1.4 1.2 1 year Vegetation Management — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.1 various Total Regulatory Assets Approved for Recovery 222.1 201.4 Total Noncurrent Regulatory Assets $ 340.2 $ 214.8 PSO December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 76.1 Total Current Regulatory Liabilities $ — $ 76.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 279.3 $ 275.5 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 48.0 46.3 38 years Advanced Metering Costs 11.5 11.4 1 year Base Plan Funding Costs — 1.3 Other Regulatory Liabilities Approved for Payment 0.9 0.6 various Total Regulatory Liabilities Approved for Payment 339.7 335.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 339.7 $ 335.1 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 8.4 $ 4.1 1 year Total Current Regulatory Assets $ 8.4 $ 4.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.8 — Regulatory Assets Currently Not Earning a Return Environmental Controls Projects 11.0 — Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.7 1.7 Rate Case Expense - Texas 1.0 0.3 Other Regulatory Assets Pending Final Regulatory Approval 1.9 0.8 Total Regulatory Assets Pending Final Regulatory Approval 95.9 5.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 1.3 0.2 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 314.2 271.9 34 years Pension and OPEB Funded Status 119.8 108.9 12 years Unamortized Loss on Reacquired Debt 5.4 6.0 27 years Medicare Subsidy 4.3 4.8 8 years Rate Case Expense - Texas 4.2 6.8 2 years Peak Demand Reduction/Energy Efficiency 3.0 1.0 2 years Deferred Restructuring Costs - Louisiana 1.9 3.5 2 years Unrealized Loss on Forward Commitments 0.3 5.5 1 year Other Regulatory Assets Approved for Recovery 0.9 1.3 various Total Regulatory Assets Approved for Recovery 455.3 409.9 Total Noncurrent Regulatory Assets $ 551.2 $ 415.8 SWEPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 3.8 $ 8.4 1 year Total Current Regulatory Liabilities $ 3.8 $ 8.4 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 409.7 $ 396.8 (a) Refundable Construction Financing Costs - Louisiana 16.2 37.4 2 years Excess Earnings - Texas 2.7 2.7 37 years Generation Recovery Rider Costs - Arkansas 1.2 1.5 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 7.3 8.5 14 years Other Regulatory Liabilities Approved for Payment 1.8 1.9 various Total Regulatory Liabilities Approved for Payment 438.9 448.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 438.9 $ 448.8 (a) Relieved as removal costs are incurred.
Indiana Michigan Power Co [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2016 2015 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 61.4 $ 38.9 1 year Under-recovered Fuel Costs - does not earn a return 95.2 76.3 1 year Total Current Regulatory Assets $ 156.6 $ 115.2 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 159.9 $ — Ohio Capacity Deferral 96.7 — Storm Related Costs 25.1 24.2 Plant Retirement Costs - Materials and Supplies 9.1 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.3 — Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 — Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 59.8 Storm Related Costs 25.9 18.2 Environmental Control Projects 24.1 — Cook Plant Turbine 12.8 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 29.1 22.0 Total Regulatory Assets Pending Final Regulatory Approval (b) 450.1 167.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 550.6 539.3 28 years Ohio Phase-In Recovery Rider 218.9 304.5 2 years Ohio Capacity Deferral 201.9 358.7 2 years Meter Replacement Costs 99.9 90.4 11 years Ohio Distribution Decoupling 41.8 37.5 2 years Advanced Metering System 20.9 3.6 4 years Basic Transmission Cost Rider 19.9 — 2 years West Virginia Delayed Customer Billing 19.5 — 2 years Asset Removal Costs 18.7 38.1 (a) Mitchell Plant Transfer 18.5 19.3 24 years Plant Retirement Costs - Asset Retirement Obligation Costs 18.3 7.6 24 years Storm Related Costs 15.3 8.8 3 years Red Rock Generating Facility 9.1 9.3 40 years Ohio Transmission Cost Recovery Rider — 12.3 Other Regulatory Assets Approved for Recovery 27.6 25.5 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (c) 1,575.0 1,385.3 62 years Pension and OPEB Funded Status 1,516.2 1,410.5 12 years Unamortized Loss on Reacquired Debt 137.8 148.7 29 years Unrealized Loss on Forward Commitments 119.1 10.7 16 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Storm Related Costs 58.7 94.6 4 years Peak Demand Reduction/Energy Efficiency 49.9 33.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 48.9 58.0 24 years Postemployment Benefits 39.1 42.6 5 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Medicare Subsidy 37.2 41.8 8 years Vegetation Management 31.4 36.9 5 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years OVEC Purchased Power 22.1 — 2 years United Mine Workers of America Pension Withdrawal 20.2 14.4 6 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year SPP Base Plan Fees 10.7 — 2 years Carbon Capture and Storage Product Validation Facility 9.1 11.7 4 years IGCC Pre-Construction Costs 8.6 10.9 24 years Transmission Cost Recovery Factor 5.3 9.9 1 year Distribution Investment Rider 2.0 12.3 2 years Other Regulatory Assets Approved for Recovery 52.5 77.8 various Total Regulatory Assets Approved for Recovery 5,175.4 4,972.4 Total Noncurrent Regulatory Assets $ 5,625.5 $ 5,140.3 (a) As a regulated entity, removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. As of December 31, 2016 , KPCo’s accumulated actual removal cost incurred exceeded accumulated removal cost accrued, creating an asset balance. As a result, the balance was reclassified to a regulatory asset. Within the next two years, KPCo’s removal costs accrued are expected to exceed removal costs incurred resulting in a regulatory liability. (b) As of December 31, 2016, APCo has deferred a total of $91 million as charges to accumulated depreciation related to certain plant retirements in 2015. APCo intends to address the need for depreciation rate increases in a subsequent base rate cases. (c) Includes $320 million and $288 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. AEP December 31, Remaining 2016 2015 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 3.8 $ 84.8 1 year Over-recovered Fuel Costs - does not pay a return 4.2 29.1 1 year Total Current Regulatory Liabilities $ 8.0 $ 113.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.8 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.8 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) 2,627.5 2,656.5 (b) Advanced Metering Infrastructure Surcharge 17.0 21.2 4 years Louisiana Refundable Construction Financing Costs 16.2 37.4 2 years Deferred Investment Tax Credits 12.6 14.7 42 years Excess Earnings 10.0 10.6 37 years Other Regulatory Liabilities Approved for Payment 1.6 20.5 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Deferred Investment Tax Credits 132.9 113.3 46 years Spent Nuclear Fuel 44.2 43.4 (c) Transition Charges 40.5 46.5 11 years Peak Demand Reduction/Energy Efficiency 34.0 5.3 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Advanced Metering Costs 11.5 11.4 1 year Unrealized Gain on Forward Commitments 6.2 33.8 2 years Deferred Wind Power Costs 2.1 11.8 1 year Other Regulatory Liabilities Approved for Payment 29.4 24.4 various Total Regulatory Liabilities Approved for Payment 3,750.5 3,695.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,751.3 $ 3,736.1 (a) As of December 31, 2016, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 6.2 $ 27.3 1 year Under-recovered Fuel Costs - does not earn a return 62.2 59.6 1 year Total Current Regulatory Assets $ 68.4 $ 86.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 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 (a) 39.3 57.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.4 86.5 27 years West Virginia Delayed Customer Billing 18.1 — 2 years Storm Related Costs - Virginia 4.6 8.8 2 years RTO Formation/Integration Costs 1.6 2.1 3 years Other Regulatory Assets Approved for Recovery 0.6 — various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (b) 463.5 441.7 26 years Pension and OPEB Funded Status 221.4 217.6 12 years Unamortized Loss on Reacquired Debt 97.2 101.5 29 years Storm Related Costs - West Virginia 47.8 63.5 4 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Vegetation Management Program - West Virginia 31.4 31.2 5 years Peak Demand Reduction/Energy Efficiency 19.2 3.5 4 years Postemployment Benefits 17.4 19.6 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 9.1 11.7 4 years IGCC Pre-Construction Costs - West Virginia, FERC 7.4 9.6 4 years Virginia Generation Rate Adjustment Clause 6.5 5.2 2 years Medicare Subsidy - West Virginia, FERC 4.7 5.3 8 years Uncollected Accounts - West Virginia 2.7 3.5 4 years Deferred Restructuring Costs - West Virginia 2.5 4.5 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.0 1.2 6 years Asset Retirement Obligation 0.6 2.4 1 year Transmission Agreement Phase-In - West Virginia — 1.7 Other Regulatory Assets Approved for Recovery 0.4 1.2 various Total Regulatory Assets Approved for Recovery 1,081.8 1,096.9 Total Noncurrent Regulatory Assets $ 1,121.1 $ 1,154.2 (a) As of December 31, 2016, APCo has also deferred $91 million as a charge to accumulated depreciation related to the net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements and not abandonments. APCo intends to address the need for an increase in its Virginia depreciation rates in March 2020, as part of its 2018-2019 Virginia biennial filing. (b) Includes $64 million and $59 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 616.9 $ 612.9 (a) Deferred Investment Tax Credits 0.9 1.0 42 years Regulatory Liabilities Currently Not Paying a Return Consumer Rate Relief - West Virginia 5.1 2.9 1 year Deferred Wind Power Costs - Virginia 2.1 11.8 1 year Energy Efficiency Rate Adjustment Clause - Virginia 1.5 — 2 years Unrealized Gain on Forward Commitments 1.3 8.4 2 years Other Regulatory Liabilities Approved for Payment — 0.1 various Total Regulatory Liabilities Approved for Payment 627.8 637.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 627.8 $ 637.1 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 13.0 $ 7.5 1 year Under-recovered Fuel Costs - does not earn a return 13.1 4.1 1 year Total Current Regulatory Assets $ 26.1 $ 11.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ — $ 11.6 Regulatory Assets Currently Not Earning a Return Cook Uprate Project 36.3 — Cook Plant Turbine 12.8 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 8.1 4.2 Rockport Plant Dry Sorbent Injection System - Indiana 6.6 2.8 Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana — 27.1 Stranded Costs on Abandoned Plants — 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.9 — Total Regulatory Assets Pending Final Regulatory Approval 64.7 59.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 252.8 260.3 28 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.3 6.6 22 years RTO Formation/Integration Costs 1.2 1.5 3 years Other Regulatory Assets Approved for Recovery 1.3 1.0 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (a) 302.6 246.8 32 years Pension and OPEB Funded Status 141.9 126.4 12 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years Postemployment Benefits 11.4 10.7 5 years Unamortized Loss on Reacquired Debt 10.7 12.0 16 years Medicare Subsidy 8.2 9.2 8 years Litigation Settlement - Indiana 7.6 8.6 9 years River Transportation Division Expenses 3.7 — 1 year Peak Demand Reduction/Energy Efficiency 3.6 10.6 2 years Capacity Costs - Indiana 0.4 7.5 1 year Unrealized Loss on Forward Commitments 0.1 3.2 2 years PJM Expense - Indiana — 4.1 Storm Related Costs - Indiana — 1.8 Other Regulatory Assets Approved for Recovery 0.6 1.1 various Total Regulatory Assets Approved for Recovery 851.9 745.0 Total Noncurrent Regulatory Assets $ 916.6 $ 804.3 (a) Includes $74 million and $69 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rate s. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 0.3 Total Current Regulatory Liabilities $ — $ 0.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) $ 236.5 $ 350.6 (b) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Spent Nuclear Fuel 44.2 43.4 (c) Deferred Investment Tax Credits 38.8 35.0 20 years Deferred Cook Plant Life Cycle Management Project Costs - Indiana 4.6 — 3 years PJM Expense - Indiana 4.2 — 2 years Unrealized Gain on Forward Commitments 2.4 7.1 2 years Rockport Plant Dry Sorbent Injection 1.7 0.4 2 years Storm Related Costs - Indiana 1.2 — 1 year River Transportation Division Expenses — 1.9 Other Regulatory Liabilities Approved for Payment 0.7 1.3 various Total Regulatory Liabilities Approved for Payment 1,065.5 1,076.2 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,065.5 $ 1,076.2 (a) As of December 31, 2016, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ 96.7 $ — Regulatory Assets Currently Not Earning a Return gridSMART ® Costs 4.1 1.3 Total Regulatory Assets Pending Final Regulatory Approval 100.8 1.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Phase-In Recovery Rider 218.9 304.5 2 years Capacity Deferral 201.9 358.7 2 years Distribution Decoupling 41.8 37.5 2 years Basic Transmission Cost Rider 19.9 — 2 years RTO Formation/Integration Costs 2.5 3.1 3 years Economic Development Rider 1.7 — 2 years Transmission Cost Recovery Rider — 12.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 225.2 219.4 12 years Income Taxes, Net (a) 126.4 129.0 28 years Unrealized Loss on Forward Commitments 118.6 — 16 years OVEC Purchased Power 22.1 — 2 years Unamortized Loss on Reacquired Debt 9.1 10.4 22 years Medicare Subsidy 8.3 9.3 8 years Postemployment Benefits 6.8 7.3 5 years Distribution Investment Rider 2.0 12.3 2 years Partnership with Ohio Contribution 1.4 2.4 2 years gridSMART ® Costs — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.0 various Total Regulatory Assets Approved for Recovery 1,006.7 1,111.7 Total Noncurrent Regulatory Assets $ 1,107.5 $ 1,113.0 (a) Includes $76 million and $82 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. OPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 4.2 $ 27.6 1 year Total Current Regulatory Liabilities $ 4.2 $ 27.6 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 432.4 422.3 (a) Basic Transmission Cost Rider 0.3 4.9 2 years Economic Development Rider — 5.0 Regulatory Liabilities Currently Not Paying a Return Peak Demand Reduction/Energy Efficiency 29.0 1.5 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Storm Related Costs 5.3 1.3 2 years Deferred Asset Phase-In Rider 4.5 5.1 4 years Unrealized Gain on Forward Commitments — 15.3 Regulatory Settlement — 9.0 Other Regulatory Liabilities Approved for Payment 0.9 1.0 various Total Regulatory Liabilities Approved for Payment 506.0 473.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 506.2 $ 514.2 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 33.8 $ — 1 year Total Current Regulatory Assets $ 33.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 84.5 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.5 — Regulatory Assets Currently Not Earning a Return Storm Related Costs 20.0 12.3 Environmental Control Projects 13.1 — Other Regulatory Assets Pending Final Regulatory Approval — 1.1 Total Regulatory Assets Pending Final Regulatory Approval 118.1 13.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 50.1 35.8 8 years Storm Related Costs 10.8 — 3 years Red Rock Generating Facility 9.1 9.3 40 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 98.1 95.1 12 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year Storm Related Costs — 15.4 SPP Base Plan Fees 10.7 — 2 years Peak Demand Reduction/Energy Efficiency 10.3 11.8 2 years Income Taxes, Net 9.3 6.1 33 years Unamortized Loss on Reacquired Debt 5.8 6.8 16 years Medicare Subsidy 3.9 4.4 8 years Rate Case Expenses 1.4 1.2 1 year Vegetation Management — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.1 various Total Regulatory Assets Approved for Recovery 222.1 201.4 Total Noncurrent Regulatory Assets $ 340.2 $ 214.8 PSO December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 76.1 Total Current Regulatory Liabilities $ — $ 76.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 279.3 $ 275.5 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 48.0 46.3 38 years Advanced Metering Costs 11.5 11.4 1 year Base Plan Funding Costs — 1.3 Other Regulatory Liabilities Approved for Payment 0.9 0.6 various Total Regulatory Liabilities Approved for Payment 339.7 335.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 339.7 $ 335.1 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 8.4 $ 4.1 1 year Total Current Regulatory Assets $ 8.4 $ 4.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.8 — Regulatory Assets Currently Not Earning a Return Environmental Controls Projects 11.0 — Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.7 1.7 Rate Case Expense - Texas 1.0 0.3 Other Regulatory Assets Pending Final Regulatory Approval 1.9 0.8 Total Regulatory Assets Pending Final Regulatory Approval 95.9 5.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 1.3 0.2 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 314.2 271.9 34 years Pension and OPEB Funded Status 119.8 108.9 12 years Unamortized Loss on Reacquired Debt 5.4 6.0 27 years Medicare Subsidy 4.3 4.8 8 years Rate Case Expense - Texas 4.2 6.8 2 years Peak Demand Reduction/Energy Efficiency 3.0 1.0 2 years Deferred Restructuring Costs - Louisiana 1.9 3.5 2 years Unrealized Loss on Forward Commitments 0.3 5.5 1 year Other Regulatory Assets Approved for Recovery 0.9 1.3 various Total Regulatory Assets Approved for Recovery 455.3 409.9 Total Noncurrent Regulatory Assets $ 551.2 $ 415.8 SWEPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 3.8 $ 8.4 1 year Total Current Regulatory Liabilities $ 3.8 $ 8.4 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 409.7 $ 396.8 (a) Refundable Construction Financing Costs - Louisiana 16.2 37.4 2 years Excess Earnings - Texas 2.7 2.7 37 years Generation Recovery Rider Costs - Arkansas 1.2 1.5 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 7.3 8.5 14 years Other Regulatory Liabilities Approved for Payment 1.8 1.9 various Total Regulatory Liabilities Approved for Payment 438.9 448.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 438.9 $ 448.8 (a) Relieved as removal costs are incurred.
Ohio Power Co [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2016 2015 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 61.4 $ 38.9 1 year Under-recovered Fuel Costs - does not earn a return 95.2 76.3 1 year Total Current Regulatory Assets $ 156.6 $ 115.2 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 159.9 $ — Ohio Capacity Deferral 96.7 — Storm Related Costs 25.1 24.2 Plant Retirement Costs - Materials and Supplies 9.1 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.3 — Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 — Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 59.8 Storm Related Costs 25.9 18.2 Environmental Control Projects 24.1 — Cook Plant Turbine 12.8 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 29.1 22.0 Total Regulatory Assets Pending Final Regulatory Approval (b) 450.1 167.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 550.6 539.3 28 years Ohio Phase-In Recovery Rider 218.9 304.5 2 years Ohio Capacity Deferral 201.9 358.7 2 years Meter Replacement Costs 99.9 90.4 11 years Ohio Distribution Decoupling 41.8 37.5 2 years Advanced Metering System 20.9 3.6 4 years Basic Transmission Cost Rider 19.9 — 2 years West Virginia Delayed Customer Billing 19.5 — 2 years Asset Removal Costs 18.7 38.1 (a) Mitchell Plant Transfer 18.5 19.3 24 years Plant Retirement Costs - Asset Retirement Obligation Costs 18.3 7.6 24 years Storm Related Costs 15.3 8.8 3 years Red Rock Generating Facility 9.1 9.3 40 years Ohio Transmission Cost Recovery Rider — 12.3 Other Regulatory Assets Approved for Recovery 27.6 25.5 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (c) 1,575.0 1,385.3 62 years Pension and OPEB Funded Status 1,516.2 1,410.5 12 years Unamortized Loss on Reacquired Debt 137.8 148.7 29 years Unrealized Loss on Forward Commitments 119.1 10.7 16 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Storm Related Costs 58.7 94.6 4 years Peak Demand Reduction/Energy Efficiency 49.9 33.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 48.9 58.0 24 years Postemployment Benefits 39.1 42.6 5 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Medicare Subsidy 37.2 41.8 8 years Vegetation Management 31.4 36.9 5 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years OVEC Purchased Power 22.1 — 2 years United Mine Workers of America Pension Withdrawal 20.2 14.4 6 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year SPP Base Plan Fees 10.7 — 2 years Carbon Capture and Storage Product Validation Facility 9.1 11.7 4 years IGCC Pre-Construction Costs 8.6 10.9 24 years Transmission Cost Recovery Factor 5.3 9.9 1 year Distribution Investment Rider 2.0 12.3 2 years Other Regulatory Assets Approved for Recovery 52.5 77.8 various Total Regulatory Assets Approved for Recovery 5,175.4 4,972.4 Total Noncurrent Regulatory Assets $ 5,625.5 $ 5,140.3 (a) As a regulated entity, removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. As of December 31, 2016 , KPCo’s accumulated actual removal cost incurred exceeded accumulated removal cost accrued, creating an asset balance. As a result, the balance was reclassified to a regulatory asset. Within the next two years, KPCo’s removal costs accrued are expected to exceed removal costs incurred resulting in a regulatory liability. (b) As of December 31, 2016, APCo has deferred a total of $91 million as charges to accumulated depreciation related to certain plant retirements in 2015. APCo intends to address the need for depreciation rate increases in a subsequent base rate cases. (c) Includes $320 million and $288 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. AEP December 31, Remaining 2016 2015 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 3.8 $ 84.8 1 year Over-recovered Fuel Costs - does not pay a return 4.2 29.1 1 year Total Current Regulatory Liabilities $ 8.0 $ 113.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.8 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.8 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) 2,627.5 2,656.5 (b) Advanced Metering Infrastructure Surcharge 17.0 21.2 4 years Louisiana Refundable Construction Financing Costs 16.2 37.4 2 years Deferred Investment Tax Credits 12.6 14.7 42 years Excess Earnings 10.0 10.6 37 years Other Regulatory Liabilities Approved for Payment 1.6 20.5 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Deferred Investment Tax Credits 132.9 113.3 46 years Spent Nuclear Fuel 44.2 43.4 (c) Transition Charges 40.5 46.5 11 years Peak Demand Reduction/Energy Efficiency 34.0 5.3 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Advanced Metering Costs 11.5 11.4 1 year Unrealized Gain on Forward Commitments 6.2 33.8 2 years Deferred Wind Power Costs 2.1 11.8 1 year Other Regulatory Liabilities Approved for Payment 29.4 24.4 various Total Regulatory Liabilities Approved for Payment 3,750.5 3,695.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,751.3 $ 3,736.1 (a) As of December 31, 2016, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 6.2 $ 27.3 1 year Under-recovered Fuel Costs - does not earn a return 62.2 59.6 1 year Total Current Regulatory Assets $ 68.4 $ 86.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 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 (a) 39.3 57.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.4 86.5 27 years West Virginia Delayed Customer Billing 18.1 — 2 years Storm Related Costs - Virginia 4.6 8.8 2 years RTO Formation/Integration Costs 1.6 2.1 3 years Other Regulatory Assets Approved for Recovery 0.6 — various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (b) 463.5 441.7 26 years Pension and OPEB Funded Status 221.4 217.6 12 years Unamortized Loss on Reacquired Debt 97.2 101.5 29 years Storm Related Costs - West Virginia 47.8 63.5 4 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Vegetation Management Program - West Virginia 31.4 31.2 5 years Peak Demand Reduction/Energy Efficiency 19.2 3.5 4 years Postemployment Benefits 17.4 19.6 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 9.1 11.7 4 years IGCC Pre-Construction Costs - West Virginia, FERC 7.4 9.6 4 years Virginia Generation Rate Adjustment Clause 6.5 5.2 2 years Medicare Subsidy - West Virginia, FERC 4.7 5.3 8 years Uncollected Accounts - West Virginia 2.7 3.5 4 years Deferred Restructuring Costs - West Virginia 2.5 4.5 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.0 1.2 6 years Asset Retirement Obligation 0.6 2.4 1 year Transmission Agreement Phase-In - West Virginia — 1.7 Other Regulatory Assets Approved for Recovery 0.4 1.2 various Total Regulatory Assets Approved for Recovery 1,081.8 1,096.9 Total Noncurrent Regulatory Assets $ 1,121.1 $ 1,154.2 (a) As of December 31, 2016, APCo has also deferred $91 million as a charge to accumulated depreciation related to the net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements and not abandonments. APCo intends to address the need for an increase in its Virginia depreciation rates in March 2020, as part of its 2018-2019 Virginia biennial filing. (b) Includes $64 million and $59 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 616.9 $ 612.9 (a) Deferred Investment Tax Credits 0.9 1.0 42 years Regulatory Liabilities Currently Not Paying a Return Consumer Rate Relief - West Virginia 5.1 2.9 1 year Deferred Wind Power Costs - Virginia 2.1 11.8 1 year Energy Efficiency Rate Adjustment Clause - Virginia 1.5 — 2 years Unrealized Gain on Forward Commitments 1.3 8.4 2 years Other Regulatory Liabilities Approved for Payment — 0.1 various Total Regulatory Liabilities Approved for Payment 627.8 637.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 627.8 $ 637.1 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 13.0 $ 7.5 1 year Under-recovered Fuel Costs - does not earn a return 13.1 4.1 1 year Total Current Regulatory Assets $ 26.1 $ 11.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ — $ 11.6 Regulatory Assets Currently Not Earning a Return Cook Uprate Project 36.3 — Cook Plant Turbine 12.8 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 8.1 4.2 Rockport Plant Dry Sorbent Injection System - Indiana 6.6 2.8 Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana — 27.1 Stranded Costs on Abandoned Plants — 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.9 — Total Regulatory Assets Pending Final Regulatory Approval 64.7 59.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 252.8 260.3 28 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.3 6.6 22 years RTO Formation/Integration Costs 1.2 1.5 3 years Other Regulatory Assets Approved for Recovery 1.3 1.0 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (a) 302.6 246.8 32 years Pension and OPEB Funded Status 141.9 126.4 12 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years Postemployment Benefits 11.4 10.7 5 years Unamortized Loss on Reacquired Debt 10.7 12.0 16 years Medicare Subsidy 8.2 9.2 8 years Litigation Settlement - Indiana 7.6 8.6 9 years River Transportation Division Expenses 3.7 — 1 year Peak Demand Reduction/Energy Efficiency 3.6 10.6 2 years Capacity Costs - Indiana 0.4 7.5 1 year Unrealized Loss on Forward Commitments 0.1 3.2 2 years PJM Expense - Indiana — 4.1 Storm Related Costs - Indiana — 1.8 Other Regulatory Assets Approved for Recovery 0.6 1.1 various Total Regulatory Assets Approved for Recovery 851.9 745.0 Total Noncurrent Regulatory Assets $ 916.6 $ 804.3 (a) Includes $74 million and $69 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rate s. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 0.3 Total Current Regulatory Liabilities $ — $ 0.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) $ 236.5 $ 350.6 (b) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Spent Nuclear Fuel 44.2 43.4 (c) Deferred Investment Tax Credits 38.8 35.0 20 years Deferred Cook Plant Life Cycle Management Project Costs - Indiana 4.6 — 3 years PJM Expense - Indiana 4.2 — 2 years Unrealized Gain on Forward Commitments 2.4 7.1 2 years Rockport Plant Dry Sorbent Injection 1.7 0.4 2 years Storm Related Costs - Indiana 1.2 — 1 year River Transportation Division Expenses — 1.9 Other Regulatory Liabilities Approved for Payment 0.7 1.3 various Total Regulatory Liabilities Approved for Payment 1,065.5 1,076.2 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,065.5 $ 1,076.2 (a) As of December 31, 2016, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ 96.7 $ — Regulatory Assets Currently Not Earning a Return gridSMART ® Costs 4.1 1.3 Total Regulatory Assets Pending Final Regulatory Approval 100.8 1.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Phase-In Recovery Rider 218.9 304.5 2 years Capacity Deferral 201.9 358.7 2 years Distribution Decoupling 41.8 37.5 2 years Basic Transmission Cost Rider 19.9 — 2 years RTO Formation/Integration Costs 2.5 3.1 3 years Economic Development Rider 1.7 — 2 years Transmission Cost Recovery Rider — 12.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 225.2 219.4 12 years Income Taxes, Net (a) 126.4 129.0 28 years Unrealized Loss on Forward Commitments 118.6 — 16 years OVEC Purchased Power 22.1 — 2 years Unamortized Loss on Reacquired Debt 9.1 10.4 22 years Medicare Subsidy 8.3 9.3 8 years Postemployment Benefits 6.8 7.3 5 years Distribution Investment Rider 2.0 12.3 2 years Partnership with Ohio Contribution 1.4 2.4 2 years gridSMART ® Costs — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.0 various Total Regulatory Assets Approved for Recovery 1,006.7 1,111.7 Total Noncurrent Regulatory Assets $ 1,107.5 $ 1,113.0 (a) Includes $76 million and $82 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. OPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 4.2 $ 27.6 1 year Total Current Regulatory Liabilities $ 4.2 $ 27.6 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 432.4 422.3 (a) Basic Transmission Cost Rider 0.3 4.9 2 years Economic Development Rider — 5.0 Regulatory Liabilities Currently Not Paying a Return Peak Demand Reduction/Energy Efficiency 29.0 1.5 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Storm Related Costs 5.3 1.3 2 years Deferred Asset Phase-In Rider 4.5 5.1 4 years Unrealized Gain on Forward Commitments — 15.3 Regulatory Settlement — 9.0 Other Regulatory Liabilities Approved for Payment 0.9 1.0 various Total Regulatory Liabilities Approved for Payment 506.0 473.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 506.2 $ 514.2 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 33.8 $ — 1 year Total Current Regulatory Assets $ 33.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 84.5 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.5 — Regulatory Assets Currently Not Earning a Return Storm Related Costs 20.0 12.3 Environmental Control Projects 13.1 — Other Regulatory Assets Pending Final Regulatory Approval — 1.1 Total Regulatory Assets Pending Final Regulatory Approval 118.1 13.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 50.1 35.8 8 years Storm Related Costs 10.8 — 3 years Red Rock Generating Facility 9.1 9.3 40 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 98.1 95.1 12 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year Storm Related Costs — 15.4 SPP Base Plan Fees 10.7 — 2 years Peak Demand Reduction/Energy Efficiency 10.3 11.8 2 years Income Taxes, Net 9.3 6.1 33 years Unamortized Loss on Reacquired Debt 5.8 6.8 16 years Medicare Subsidy 3.9 4.4 8 years Rate Case Expenses 1.4 1.2 1 year Vegetation Management — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.1 various Total Regulatory Assets Approved for Recovery 222.1 201.4 Total Noncurrent Regulatory Assets $ 340.2 $ 214.8 PSO December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 76.1 Total Current Regulatory Liabilities $ — $ 76.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 279.3 $ 275.5 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 48.0 46.3 38 years Advanced Metering Costs 11.5 11.4 1 year Base Plan Funding Costs — 1.3 Other Regulatory Liabilities Approved for Payment 0.9 0.6 various Total Regulatory Liabilities Approved for Payment 339.7 335.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 339.7 $ 335.1 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 8.4 $ 4.1 1 year Total Current Regulatory Assets $ 8.4 $ 4.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.8 — Regulatory Assets Currently Not Earning a Return Environmental Controls Projects 11.0 — Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.7 1.7 Rate Case Expense - Texas 1.0 0.3 Other Regulatory Assets Pending Final Regulatory Approval 1.9 0.8 Total Regulatory Assets Pending Final Regulatory Approval 95.9 5.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 1.3 0.2 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 314.2 271.9 34 years Pension and OPEB Funded Status 119.8 108.9 12 years Unamortized Loss on Reacquired Debt 5.4 6.0 27 years Medicare Subsidy 4.3 4.8 8 years Rate Case Expense - Texas 4.2 6.8 2 years Peak Demand Reduction/Energy Efficiency 3.0 1.0 2 years Deferred Restructuring Costs - Louisiana 1.9 3.5 2 years Unrealized Loss on Forward Commitments 0.3 5.5 1 year Other Regulatory Assets Approved for Recovery 0.9 1.3 various Total Regulatory Assets Approved for Recovery 455.3 409.9 Total Noncurrent Regulatory Assets $ 551.2 $ 415.8 SWEPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 3.8 $ 8.4 1 year Total Current Regulatory Liabilities $ 3.8 $ 8.4 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 409.7 $ 396.8 (a) Refundable Construction Financing Costs - Louisiana 16.2 37.4 2 years Excess Earnings - Texas 2.7 2.7 37 years Generation Recovery Rider Costs - Arkansas 1.2 1.5 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 7.3 8.5 14 years Other Regulatory Liabilities Approved for Payment 1.8 1.9 various Total Regulatory Liabilities Approved for Payment 438.9 448.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 438.9 $ 448.8 (a) Relieved as removal costs are incurred.
Public Service Co Of Oklahoma [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2016 2015 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 61.4 $ 38.9 1 year Under-recovered Fuel Costs - does not earn a return 95.2 76.3 1 year Total Current Regulatory Assets $ 156.6 $ 115.2 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 159.9 $ — Ohio Capacity Deferral 96.7 — Storm Related Costs 25.1 24.2 Plant Retirement Costs - Materials and Supplies 9.1 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.3 — Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 — Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 59.8 Storm Related Costs 25.9 18.2 Environmental Control Projects 24.1 — Cook Plant Turbine 12.8 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 29.1 22.0 Total Regulatory Assets Pending Final Regulatory Approval (b) 450.1 167.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 550.6 539.3 28 years Ohio Phase-In Recovery Rider 218.9 304.5 2 years Ohio Capacity Deferral 201.9 358.7 2 years Meter Replacement Costs 99.9 90.4 11 years Ohio Distribution Decoupling 41.8 37.5 2 years Advanced Metering System 20.9 3.6 4 years Basic Transmission Cost Rider 19.9 — 2 years West Virginia Delayed Customer Billing 19.5 — 2 years Asset Removal Costs 18.7 38.1 (a) Mitchell Plant Transfer 18.5 19.3 24 years Plant Retirement Costs - Asset Retirement Obligation Costs 18.3 7.6 24 years Storm Related Costs 15.3 8.8 3 years Red Rock Generating Facility 9.1 9.3 40 years Ohio Transmission Cost Recovery Rider — 12.3 Other Regulatory Assets Approved for Recovery 27.6 25.5 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (c) 1,575.0 1,385.3 62 years Pension and OPEB Funded Status 1,516.2 1,410.5 12 years Unamortized Loss on Reacquired Debt 137.8 148.7 29 years Unrealized Loss on Forward Commitments 119.1 10.7 16 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Storm Related Costs 58.7 94.6 4 years Peak Demand Reduction/Energy Efficiency 49.9 33.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 48.9 58.0 24 years Postemployment Benefits 39.1 42.6 5 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Medicare Subsidy 37.2 41.8 8 years Vegetation Management 31.4 36.9 5 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years OVEC Purchased Power 22.1 — 2 years United Mine Workers of America Pension Withdrawal 20.2 14.4 6 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year SPP Base Plan Fees 10.7 — 2 years Carbon Capture and Storage Product Validation Facility 9.1 11.7 4 years IGCC Pre-Construction Costs 8.6 10.9 24 years Transmission Cost Recovery Factor 5.3 9.9 1 year Distribution Investment Rider 2.0 12.3 2 years Other Regulatory Assets Approved for Recovery 52.5 77.8 various Total Regulatory Assets Approved for Recovery 5,175.4 4,972.4 Total Noncurrent Regulatory Assets $ 5,625.5 $ 5,140.3 (a) As a regulated entity, removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. As of December 31, 2016 , KPCo’s accumulated actual removal cost incurred exceeded accumulated removal cost accrued, creating an asset balance. As a result, the balance was reclassified to a regulatory asset. Within the next two years, KPCo’s removal costs accrued are expected to exceed removal costs incurred resulting in a regulatory liability. (b) As of December 31, 2016, APCo has deferred a total of $91 million as charges to accumulated depreciation related to certain plant retirements in 2015. APCo intends to address the need for depreciation rate increases in a subsequent base rate cases. (c) Includes $320 million and $288 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. AEP December 31, Remaining 2016 2015 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 3.8 $ 84.8 1 year Over-recovered Fuel Costs - does not pay a return 4.2 29.1 1 year Total Current Regulatory Liabilities $ 8.0 $ 113.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.8 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.8 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) 2,627.5 2,656.5 (b) Advanced Metering Infrastructure Surcharge 17.0 21.2 4 years Louisiana Refundable Construction Financing Costs 16.2 37.4 2 years Deferred Investment Tax Credits 12.6 14.7 42 years Excess Earnings 10.0 10.6 37 years Other Regulatory Liabilities Approved for Payment 1.6 20.5 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Deferred Investment Tax Credits 132.9 113.3 46 years Spent Nuclear Fuel 44.2 43.4 (c) Transition Charges 40.5 46.5 11 years Peak Demand Reduction/Energy Efficiency 34.0 5.3 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Advanced Metering Costs 11.5 11.4 1 year Unrealized Gain on Forward Commitments 6.2 33.8 2 years Deferred Wind Power Costs 2.1 11.8 1 year Other Regulatory Liabilities Approved for Payment 29.4 24.4 various Total Regulatory Liabilities Approved for Payment 3,750.5 3,695.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,751.3 $ 3,736.1 (a) As of December 31, 2016, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 6.2 $ 27.3 1 year Under-recovered Fuel Costs - does not earn a return 62.2 59.6 1 year Total Current Regulatory Assets $ 68.4 $ 86.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 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 (a) 39.3 57.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.4 86.5 27 years West Virginia Delayed Customer Billing 18.1 — 2 years Storm Related Costs - Virginia 4.6 8.8 2 years RTO Formation/Integration Costs 1.6 2.1 3 years Other Regulatory Assets Approved for Recovery 0.6 — various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (b) 463.5 441.7 26 years Pension and OPEB Funded Status 221.4 217.6 12 years Unamortized Loss on Reacquired Debt 97.2 101.5 29 years Storm Related Costs - West Virginia 47.8 63.5 4 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Vegetation Management Program - West Virginia 31.4 31.2 5 years Peak Demand Reduction/Energy Efficiency 19.2 3.5 4 years Postemployment Benefits 17.4 19.6 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 9.1 11.7 4 years IGCC Pre-Construction Costs - West Virginia, FERC 7.4 9.6 4 years Virginia Generation Rate Adjustment Clause 6.5 5.2 2 years Medicare Subsidy - West Virginia, FERC 4.7 5.3 8 years Uncollected Accounts - West Virginia 2.7 3.5 4 years Deferred Restructuring Costs - West Virginia 2.5 4.5 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.0 1.2 6 years Asset Retirement Obligation 0.6 2.4 1 year Transmission Agreement Phase-In - West Virginia — 1.7 Other Regulatory Assets Approved for Recovery 0.4 1.2 various Total Regulatory Assets Approved for Recovery 1,081.8 1,096.9 Total Noncurrent Regulatory Assets $ 1,121.1 $ 1,154.2 (a) As of December 31, 2016, APCo has also deferred $91 million as a charge to accumulated depreciation related to the net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements and not abandonments. APCo intends to address the need for an increase in its Virginia depreciation rates in March 2020, as part of its 2018-2019 Virginia biennial filing. (b) Includes $64 million and $59 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 616.9 $ 612.9 (a) Deferred Investment Tax Credits 0.9 1.0 42 years Regulatory Liabilities Currently Not Paying a Return Consumer Rate Relief - West Virginia 5.1 2.9 1 year Deferred Wind Power Costs - Virginia 2.1 11.8 1 year Energy Efficiency Rate Adjustment Clause - Virginia 1.5 — 2 years Unrealized Gain on Forward Commitments 1.3 8.4 2 years Other Regulatory Liabilities Approved for Payment — 0.1 various Total Regulatory Liabilities Approved for Payment 627.8 637.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 627.8 $ 637.1 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 13.0 $ 7.5 1 year Under-recovered Fuel Costs - does not earn a return 13.1 4.1 1 year Total Current Regulatory Assets $ 26.1 $ 11.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ — $ 11.6 Regulatory Assets Currently Not Earning a Return Cook Uprate Project 36.3 — Cook Plant Turbine 12.8 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 8.1 4.2 Rockport Plant Dry Sorbent Injection System - Indiana 6.6 2.8 Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana — 27.1 Stranded Costs on Abandoned Plants — 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.9 — Total Regulatory Assets Pending Final Regulatory Approval 64.7 59.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 252.8 260.3 28 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.3 6.6 22 years RTO Formation/Integration Costs 1.2 1.5 3 years Other Regulatory Assets Approved for Recovery 1.3 1.0 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (a) 302.6 246.8 32 years Pension and OPEB Funded Status 141.9 126.4 12 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years Postemployment Benefits 11.4 10.7 5 years Unamortized Loss on Reacquired Debt 10.7 12.0 16 years Medicare Subsidy 8.2 9.2 8 years Litigation Settlement - Indiana 7.6 8.6 9 years River Transportation Division Expenses 3.7 — 1 year Peak Demand Reduction/Energy Efficiency 3.6 10.6 2 years Capacity Costs - Indiana 0.4 7.5 1 year Unrealized Loss on Forward Commitments 0.1 3.2 2 years PJM Expense - Indiana — 4.1 Storm Related Costs - Indiana — 1.8 Other Regulatory Assets Approved for Recovery 0.6 1.1 various Total Regulatory Assets Approved for Recovery 851.9 745.0 Total Noncurrent Regulatory Assets $ 916.6 $ 804.3 (a) Includes $74 million and $69 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rate s. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 0.3 Total Current Regulatory Liabilities $ — $ 0.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) $ 236.5 $ 350.6 (b) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Spent Nuclear Fuel 44.2 43.4 (c) Deferred Investment Tax Credits 38.8 35.0 20 years Deferred Cook Plant Life Cycle Management Project Costs - Indiana 4.6 — 3 years PJM Expense - Indiana 4.2 — 2 years Unrealized Gain on Forward Commitments 2.4 7.1 2 years Rockport Plant Dry Sorbent Injection 1.7 0.4 2 years Storm Related Costs - Indiana 1.2 — 1 year River Transportation Division Expenses — 1.9 Other Regulatory Liabilities Approved for Payment 0.7 1.3 various Total Regulatory Liabilities Approved for Payment 1,065.5 1,076.2 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,065.5 $ 1,076.2 (a) As of December 31, 2016, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ 96.7 $ — Regulatory Assets Currently Not Earning a Return gridSMART ® Costs 4.1 1.3 Total Regulatory Assets Pending Final Regulatory Approval 100.8 1.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Phase-In Recovery Rider 218.9 304.5 2 years Capacity Deferral 201.9 358.7 2 years Distribution Decoupling 41.8 37.5 2 years Basic Transmission Cost Rider 19.9 — 2 years RTO Formation/Integration Costs 2.5 3.1 3 years Economic Development Rider 1.7 — 2 years Transmission Cost Recovery Rider — 12.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 225.2 219.4 12 years Income Taxes, Net (a) 126.4 129.0 28 years Unrealized Loss on Forward Commitments 118.6 — 16 years OVEC Purchased Power 22.1 — 2 years Unamortized Loss on Reacquired Debt 9.1 10.4 22 years Medicare Subsidy 8.3 9.3 8 years Postemployment Benefits 6.8 7.3 5 years Distribution Investment Rider 2.0 12.3 2 years Partnership with Ohio Contribution 1.4 2.4 2 years gridSMART ® Costs — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.0 various Total Regulatory Assets Approved for Recovery 1,006.7 1,111.7 Total Noncurrent Regulatory Assets $ 1,107.5 $ 1,113.0 (a) Includes $76 million and $82 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. OPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 4.2 $ 27.6 1 year Total Current Regulatory Liabilities $ 4.2 $ 27.6 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 432.4 422.3 (a) Basic Transmission Cost Rider 0.3 4.9 2 years Economic Development Rider — 5.0 Regulatory Liabilities Currently Not Paying a Return Peak Demand Reduction/Energy Efficiency 29.0 1.5 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Storm Related Costs 5.3 1.3 2 years Deferred Asset Phase-In Rider 4.5 5.1 4 years Unrealized Gain on Forward Commitments — 15.3 Regulatory Settlement — 9.0 Other Regulatory Liabilities Approved for Payment 0.9 1.0 various Total Regulatory Liabilities Approved for Payment 506.0 473.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 506.2 $ 514.2 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 33.8 $ — 1 year Total Current Regulatory Assets $ 33.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 84.5 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.5 — Regulatory Assets Currently Not Earning a Return Storm Related Costs 20.0 12.3 Environmental Control Projects 13.1 — Other Regulatory Assets Pending Final Regulatory Approval — 1.1 Total Regulatory Assets Pending Final Regulatory Approval 118.1 13.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 50.1 35.8 8 years Storm Related Costs 10.8 — 3 years Red Rock Generating Facility 9.1 9.3 40 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 98.1 95.1 12 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year Storm Related Costs — 15.4 SPP Base Plan Fees 10.7 — 2 years Peak Demand Reduction/Energy Efficiency 10.3 11.8 2 years Income Taxes, Net 9.3 6.1 33 years Unamortized Loss on Reacquired Debt 5.8 6.8 16 years Medicare Subsidy 3.9 4.4 8 years Rate Case Expenses 1.4 1.2 1 year Vegetation Management — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.1 various Total Regulatory Assets Approved for Recovery 222.1 201.4 Total Noncurrent Regulatory Assets $ 340.2 $ 214.8 PSO December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 76.1 Total Current Regulatory Liabilities $ — $ 76.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 279.3 $ 275.5 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 48.0 46.3 38 years Advanced Metering Costs 11.5 11.4 1 year Base Plan Funding Costs — 1.3 Other Regulatory Liabilities Approved for Payment 0.9 0.6 various Total Regulatory Liabilities Approved for Payment 339.7 335.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 339.7 $ 335.1 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 8.4 $ 4.1 1 year Total Current Regulatory Assets $ 8.4 $ 4.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.8 — Regulatory Assets Currently Not Earning a Return Environmental Controls Projects 11.0 — Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.7 1.7 Rate Case Expense - Texas 1.0 0.3 Other Regulatory Assets Pending Final Regulatory Approval 1.9 0.8 Total Regulatory Assets Pending Final Regulatory Approval 95.9 5.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 1.3 0.2 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 314.2 271.9 34 years Pension and OPEB Funded Status 119.8 108.9 12 years Unamortized Loss on Reacquired Debt 5.4 6.0 27 years Medicare Subsidy 4.3 4.8 8 years Rate Case Expense - Texas 4.2 6.8 2 years Peak Demand Reduction/Energy Efficiency 3.0 1.0 2 years Deferred Restructuring Costs - Louisiana 1.9 3.5 2 years Unrealized Loss on Forward Commitments 0.3 5.5 1 year Other Regulatory Assets Approved for Recovery 0.9 1.3 various Total Regulatory Assets Approved for Recovery 455.3 409.9 Total Noncurrent Regulatory Assets $ 551.2 $ 415.8 SWEPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 3.8 $ 8.4 1 year Total Current Regulatory Liabilities $ 3.8 $ 8.4 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 409.7 $ 396.8 (a) Refundable Construction Financing Costs - Louisiana 16.2 37.4 2 years Excess Earnings - Texas 2.7 2.7 37 years Generation Recovery Rider Costs - Arkansas 1.2 1.5 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 7.3 8.5 14 years Other Regulatory Liabilities Approved for Payment 1.8 1.9 various Total Regulatory Liabilities Approved for Payment 438.9 448.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 438.9 $ 448.8 (a) Relieved as removal costs are incurred.
Southwestern Electric Power Co [Member]
Effects of Regulation	EFFECTS OF REGULATION The disclosures in this note apply to all Registrants unless indicated otherwise. Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items: AEP December 31, Remaining Recovery Period 2016 2015 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 61.4 $ 38.9 1 year Under-recovered Fuel Costs - does not earn a return 95.2 76.3 1 year Total Current Regulatory Assets $ 156.6 $ 115.2 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 159.9 $ — Ohio Capacity Deferral 96.7 — Storm Related Costs 25.1 24.2 Plant Retirement Costs - Materials and Supplies 9.1 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.3 — Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 — Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 59.8 Storm Related Costs 25.9 18.2 Environmental Control Projects 24.1 — Cook Plant Turbine 12.8 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 29.1 22.0 Total Regulatory Assets Pending Final Regulatory Approval (b) 450.1 167.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 550.6 539.3 28 years Ohio Phase-In Recovery Rider 218.9 304.5 2 years Ohio Capacity Deferral 201.9 358.7 2 years Meter Replacement Costs 99.9 90.4 11 years Ohio Distribution Decoupling 41.8 37.5 2 years Advanced Metering System 20.9 3.6 4 years Basic Transmission Cost Rider 19.9 — 2 years West Virginia Delayed Customer Billing 19.5 — 2 years Asset Removal Costs 18.7 38.1 (a) Mitchell Plant Transfer 18.5 19.3 24 years Plant Retirement Costs - Asset Retirement Obligation Costs 18.3 7.6 24 years Storm Related Costs 15.3 8.8 3 years Red Rock Generating Facility 9.1 9.3 40 years Ohio Transmission Cost Recovery Rider — 12.3 Other Regulatory Assets Approved for Recovery 27.6 25.5 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (c) 1,575.0 1,385.3 62 years Pension and OPEB Funded Status 1,516.2 1,410.5 12 years Unamortized Loss on Reacquired Debt 137.8 148.7 29 years Unrealized Loss on Forward Commitments 119.1 10.7 16 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Storm Related Costs 58.7 94.6 4 years Peak Demand Reduction/Energy Efficiency 49.9 33.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 48.9 58.0 24 years Postemployment Benefits 39.1 42.6 5 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Medicare Subsidy 37.2 41.8 8 years Vegetation Management 31.4 36.9 5 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years OVEC Purchased Power 22.1 — 2 years United Mine Workers of America Pension Withdrawal 20.2 14.4 6 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year SPP Base Plan Fees 10.7 — 2 years Carbon Capture and Storage Product Validation Facility 9.1 11.7 4 years IGCC Pre-Construction Costs 8.6 10.9 24 years Transmission Cost Recovery Factor 5.3 9.9 1 year Distribution Investment Rider 2.0 12.3 2 years Other Regulatory Assets Approved for Recovery 52.5 77.8 various Total Regulatory Assets Approved for Recovery 5,175.4 4,972.4 Total Noncurrent Regulatory Assets $ 5,625.5 $ 5,140.3 (a) As a regulated entity, removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. As of December 31, 2016 , KPCo’s accumulated actual removal cost incurred exceeded accumulated removal cost accrued, creating an asset balance. As a result, the balance was reclassified to a regulatory asset. Within the next two years, KPCo’s removal costs accrued are expected to exceed removal costs incurred resulting in a regulatory liability. (b) As of December 31, 2016, APCo has deferred a total of $91 million as charges to accumulated depreciation related to certain plant retirements in 2015. APCo intends to address the need for depreciation rate increases in a subsequent base rate cases. (c) Includes $320 million and $288 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. AEP December 31, Remaining 2016 2015 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 3.8 $ 84.8 1 year Over-recovered Fuel Costs - does not pay a return 4.2 29.1 1 year Total Current Regulatory Liabilities $ 8.0 $ 113.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.8 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.8 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) 2,627.5 2,656.5 (b) Advanced Metering Infrastructure Surcharge 17.0 21.2 4 years Louisiana Refundable Construction Financing Costs 16.2 37.4 2 years Deferred Investment Tax Credits 12.6 14.7 42 years Excess Earnings 10.0 10.6 37 years Other Regulatory Liabilities Approved for Payment 1.6 20.5 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Deferred Investment Tax Credits 132.9 113.3 46 years Spent Nuclear Fuel 44.2 43.4 (c) Transition Charges 40.5 46.5 11 years Peak Demand Reduction/Energy Efficiency 34.0 5.3 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Advanced Metering Costs 11.5 11.4 1 year Unrealized Gain on Forward Commitments 6.2 33.8 2 years Deferred Wind Power Costs 2.1 11.8 1 year Other Regulatory Liabilities Approved for Payment 29.4 24.4 various Total Regulatory Liabilities Approved for Payment 3,750.5 3,695.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,751.3 $ 3,736.1 (a) As of December 31, 2016, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 6.2 $ 27.3 1 year Under-recovered Fuel Costs - does not earn a return 62.2 59.6 1 year Total Current Regulatory Assets $ 68.4 $ 86.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 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 (a) 39.3 57.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.4 86.5 27 years West Virginia Delayed Customer Billing 18.1 — 2 years Storm Related Costs - Virginia 4.6 8.8 2 years RTO Formation/Integration Costs 1.6 2.1 3 years Other Regulatory Assets Approved for Recovery 0.6 — various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (b) 463.5 441.7 26 years Pension and OPEB Funded Status 221.4 217.6 12 years Unamortized Loss on Reacquired Debt 97.2 101.5 29 years Storm Related Costs - West Virginia 47.8 63.5 4 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Vegetation Management Program - West Virginia 31.4 31.2 5 years Peak Demand Reduction/Energy Efficiency 19.2 3.5 4 years Postemployment Benefits 17.4 19.6 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 9.1 11.7 4 years IGCC Pre-Construction Costs - West Virginia, FERC 7.4 9.6 4 years Virginia Generation Rate Adjustment Clause 6.5 5.2 2 years Medicare Subsidy - West Virginia, FERC 4.7 5.3 8 years Uncollected Accounts - West Virginia 2.7 3.5 4 years Deferred Restructuring Costs - West Virginia 2.5 4.5 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.0 1.2 6 years Asset Retirement Obligation 0.6 2.4 1 year Transmission Agreement Phase-In - West Virginia — 1.7 Other Regulatory Assets Approved for Recovery 0.4 1.2 various Total Regulatory Assets Approved for Recovery 1,081.8 1,096.9 Total Noncurrent Regulatory Assets $ 1,121.1 $ 1,154.2 (a) As of December 31, 2016, APCo has also deferred $91 million as a charge to accumulated depreciation related to the net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements and not abandonments. APCo intends to address the need for an increase in its Virginia depreciation rates in March 2020, as part of its 2018-2019 Virginia biennial filing. (b) Includes $64 million and $59 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 616.9 $ 612.9 (a) Deferred Investment Tax Credits 0.9 1.0 42 years Regulatory Liabilities Currently Not Paying a Return Consumer Rate Relief - West Virginia 5.1 2.9 1 year Deferred Wind Power Costs - Virginia 2.1 11.8 1 year Energy Efficiency Rate Adjustment Clause - Virginia 1.5 — 2 years Unrealized Gain on Forward Commitments 1.3 8.4 2 years Other Regulatory Liabilities Approved for Payment — 0.1 various Total Regulatory Liabilities Approved for Payment 627.8 637.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 627.8 $ 637.1 (a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 13.0 $ 7.5 1 year Under-recovered Fuel Costs - does not earn a return 13.1 4.1 1 year Total Current Regulatory Assets $ 26.1 $ 11.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ — $ 11.6 Regulatory Assets Currently Not Earning a Return Cook Uprate Project 36.3 — Cook Plant Turbine 12.8 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 8.1 4.2 Rockport Plant Dry Sorbent Injection System - Indiana 6.6 2.8 Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana — 27.1 Stranded Costs on Abandoned Plants — 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.9 — Total Regulatory Assets Pending Final Regulatory Approval 64.7 59.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 252.8 260.3 28 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.3 6.6 22 years RTO Formation/Integration Costs 1.2 1.5 3 years Other Regulatory Assets Approved for Recovery 1.3 1.0 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (a) 302.6 246.8 32 years Pension and OPEB Funded Status 141.9 126.4 12 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years Postemployment Benefits 11.4 10.7 5 years Unamortized Loss on Reacquired Debt 10.7 12.0 16 years Medicare Subsidy 8.2 9.2 8 years Litigation Settlement - Indiana 7.6 8.6 9 years River Transportation Division Expenses 3.7 — 1 year Peak Demand Reduction/Energy Efficiency 3.6 10.6 2 years Capacity Costs - Indiana 0.4 7.5 1 year Unrealized Loss on Forward Commitments 0.1 3.2 2 years PJM Expense - Indiana — 4.1 Storm Related Costs - Indiana — 1.8 Other Regulatory Assets Approved for Recovery 0.6 1.1 various Total Regulatory Assets Approved for Recovery 851.9 745.0 Total Noncurrent Regulatory Assets $ 916.6 $ 804.3 (a) Includes $74 million and $69 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rate s. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 0.3 Total Current Regulatory Liabilities $ — $ 0.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) $ 236.5 $ 350.6 (b) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Spent Nuclear Fuel 44.2 43.4 (c) Deferred Investment Tax Credits 38.8 35.0 20 years Deferred Cook Plant Life Cycle Management Project Costs - Indiana 4.6 — 3 years PJM Expense - Indiana 4.2 — 2 years Unrealized Gain on Forward Commitments 2.4 7.1 2 years Rockport Plant Dry Sorbent Injection 1.7 0.4 2 years Storm Related Costs - Indiana 1.2 — 1 year River Transportation Division Expenses — 1.9 Other Regulatory Liabilities Approved for Payment 0.7 1.3 various Total Regulatory Liabilities Approved for Payment 1,065.5 1,076.2 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,065.5 $ 1,076.2 (a) As of December 31, 2016, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ 96.7 $ — Regulatory Assets Currently Not Earning a Return gridSMART ® Costs 4.1 1.3 Total Regulatory Assets Pending Final Regulatory Approval 100.8 1.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Phase-In Recovery Rider 218.9 304.5 2 years Capacity Deferral 201.9 358.7 2 years Distribution Decoupling 41.8 37.5 2 years Basic Transmission Cost Rider 19.9 — 2 years RTO Formation/Integration Costs 2.5 3.1 3 years Economic Development Rider 1.7 — 2 years Transmission Cost Recovery Rider — 12.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 225.2 219.4 12 years Income Taxes, Net (a) 126.4 129.0 28 years Unrealized Loss on Forward Commitments 118.6 — 16 years OVEC Purchased Power 22.1 — 2 years Unamortized Loss on Reacquired Debt 9.1 10.4 22 years Medicare Subsidy 8.3 9.3 8 years Postemployment Benefits 6.8 7.3 5 years Distribution Investment Rider 2.0 12.3 2 years Partnership with Ohio Contribution 1.4 2.4 2 years gridSMART ® Costs — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.0 various Total Regulatory Assets Approved for Recovery 1,006.7 1,111.7 Total Noncurrent Regulatory Assets $ 1,107.5 $ 1,113.0 (a) Includes $76 million and $82 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. OPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 4.2 $ 27.6 1 year Total Current Regulatory Liabilities $ 4.2 $ 27.6 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 432.4 422.3 (a) Basic Transmission Cost Rider 0.3 4.9 2 years Economic Development Rider — 5.0 Regulatory Liabilities Currently Not Paying a Return Peak Demand Reduction/Energy Efficiency 29.0 1.5 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Storm Related Costs 5.3 1.3 2 years Deferred Asset Phase-In Rider 4.5 5.1 4 years Unrealized Gain on Forward Commitments — 15.3 Regulatory Settlement — 9.0 Other Regulatory Liabilities Approved for Payment 0.9 1.0 various Total Regulatory Liabilities Approved for Payment 506.0 473.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 506.2 $ 514.2 (a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 33.8 $ — 1 year Total Current Regulatory Assets $ 33.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 84.5 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.5 — Regulatory Assets Currently Not Earning a Return Storm Related Costs 20.0 12.3 Environmental Control Projects 13.1 — Other Regulatory Assets Pending Final Regulatory Approval — 1.1 Total Regulatory Assets Pending Final Regulatory Approval 118.1 13.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 50.1 35.8 8 years Storm Related Costs 10.8 — 3 years Red Rock Generating Facility 9.1 9.3 40 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 98.1 95.1 12 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year Storm Related Costs — 15.4 SPP Base Plan Fees 10.7 — 2 years Peak Demand Reduction/Energy Efficiency 10.3 11.8 2 years Income Taxes, Net 9.3 6.1 33 years Unamortized Loss on Reacquired Debt 5.8 6.8 16 years Medicare Subsidy 3.9 4.4 8 years Rate Case Expenses 1.4 1.2 1 year Vegetation Management — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.1 various Total Regulatory Assets Approved for Recovery 222.1 201.4 Total Noncurrent Regulatory Assets $ 340.2 $ 214.8 PSO December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 76.1 Total Current Regulatory Liabilities $ — $ 76.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 279.3 $ 275.5 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 48.0 46.3 38 years Advanced Metering Costs 11.5 11.4 1 year Base Plan Funding Costs — 1.3 Other Regulatory Liabilities Approved for Payment 0.9 0.6 various Total Regulatory Liabilities Approved for Payment 339.7 335.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 339.7 $ 335.1 (a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 8.4 $ 4.1 1 year Total Current Regulatory Assets $ 8.4 $ 4.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.8 — Regulatory Assets Currently Not Earning a Return Environmental Controls Projects 11.0 — Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.7 1.7 Rate Case Expense - Texas 1.0 0.3 Other Regulatory Assets Pending Final Regulatory Approval 1.9 0.8 Total Regulatory Assets Pending Final Regulatory Approval 95.9 5.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 1.3 0.2 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 314.2 271.9 34 years Pension and OPEB Funded Status 119.8 108.9 12 years Unamortized Loss on Reacquired Debt 5.4 6.0 27 years Medicare Subsidy 4.3 4.8 8 years Rate Case Expense - Texas 4.2 6.8 2 years Peak Demand Reduction/Energy Efficiency 3.0 1.0 2 years Deferred Restructuring Costs - Louisiana 1.9 3.5 2 years Unrealized Loss on Forward Commitments 0.3 5.5 1 year Other Regulatory Assets Approved for Recovery 0.9 1.3 various Total Regulatory Assets Approved for Recovery 455.3 409.9 Total Noncurrent Regulatory Assets $ 551.2 $ 415.8 SWEPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ 3.8 $ 8.4 1 year Total Current Regulatory Liabilities $ 3.8 $ 8.4 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 409.7 $ 396.8 (a) Refundable Construction Financing Costs - Louisiana 16.2 37.4 2 years Excess Earnings - Texas 2.7 2.7 37 years Generation Recovery Rider Costs - Arkansas 1.2 1.5 2 years Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 7.3 8.5 14 years Other Regulatory Liabilities Approved for Payment 1.8 1.9 various Total Regulatory Liabilities Approved for Payment 438.9 448.8 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 438.9 $ 448.8 (a) Relieved as removal costs are incurred.

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	12 Months Ended
	Dec. 31, 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. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2016 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) (b) $ 1,407.8 $ 1,441.6 $ 985.5 $ 371.8 $ 4,206.7 Energy and Capacity Purchase Contracts 215.5 437.1 439.1 1,740.2 2,831.9 Total $ 1,623.3 $ 1,878.7 $ 1,424.6 $ 2,112.0 $ 7,038.6 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 491.5 $ 433.8 $ 415.0 $ 1.2 $ 1,341.5 Energy and Capacity Purchase Contracts 33.4 68.9 72.4 430.7 605.4 Total $ 524.9 $ 502.7 $ 487.4 $ 431.9 $ 1,946.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 292.7 $ 277.8 $ 221.9 $ 266.1 $ 1,058.5 Energy and Capacity Purchase Contracts 118.5 247.7 249.5 497.5 1,113.2 Total $ 411.2 $ 525.5 $ 471.4 $ 763.6 $ 2,171.7 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Total $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 63.9 $ 55.5 $ 29.8 $ 14.9 $ 164.1 Energy and Capacity Purchase Contracts 90.6 181.7 179.9 282.3 734.5 Total $ 154.5 $ 237.2 $ 209.7 $ 297.2 $ 898.6 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 98.4 $ 139.7 $ 69.7 $ 22.6 $ 330.4 Energy and Capacity Purchase Contracts 32.6 66.6 62.5 175.9 337.6 Total $ 131.0 $ 206.3 $ 132.2 $ 198.5 $ 668.0 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion . 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 December 31, 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 December 31, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 149.7 January 2017 to February 2018 OPCo 0.6 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 approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2016 , SWEPCo has collected approximately $69 million through a rider for final mine closure and reclamation costs, of which $73 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of December 31, 2016, the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2016 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of December 31, 2016 , I&M’s accrual for all of these sites is $7 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $9 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2016 and 2015 , the total decommissioning trust fund balance was $1.9 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the Department of Energy (DOE) through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to zero. As of December 31, 2016 and 2015 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $311 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $6 million , $13 million and $22 million in 2016 , 2015 and 2014 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. In February 2017, the settlement agreement was extended through December 31, 2019. The proceeds reduced costs for dry cask storage. As of December 31, 2016 , I&M has deferred $22 million in Prepayments and Other Current Assets and $5 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Insurance I&M carries insurance coverage in the amount of $3 billion for a nuclear incident at the Cook Plant for decontamination, stabilization and extraordinary incidents caused by premature decommissioning. Insurance coverage for a nonnuclear property incident at the Cook Plant is $1.5 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $50 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident at $13.4 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M was initially covered for public nuclear liability for the first $375 million through commercially available insurance. Beginning in January 2017, the coverage increases to $450 million . The next level of liability coverage of up to $13 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims 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, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement has been reached in the three class actions and the district court issued preliminary approval of that settlement on January 26, 2017. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a tentative settlement was reached for the remaining case, subject to final documentation. Management does not expect the settlement to have a material impact on the financial statements. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and stayed the entire case pending oral argument in March 2017. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Appalachian Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2016 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) (b) $ 1,407.8 $ 1,441.6 $ 985.5 $ 371.8 $ 4,206.7 Energy and Capacity Purchase Contracts 215.5 437.1 439.1 1,740.2 2,831.9 Total $ 1,623.3 $ 1,878.7 $ 1,424.6 $ 2,112.0 $ 7,038.6 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 491.5 $ 433.8 $ 415.0 $ 1.2 $ 1,341.5 Energy and Capacity Purchase Contracts 33.4 68.9 72.4 430.7 605.4 Total $ 524.9 $ 502.7 $ 487.4 $ 431.9 $ 1,946.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 292.7 $ 277.8 $ 221.9 $ 266.1 $ 1,058.5 Energy and Capacity Purchase Contracts 118.5 247.7 249.5 497.5 1,113.2 Total $ 411.2 $ 525.5 $ 471.4 $ 763.6 $ 2,171.7 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Total $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 63.9 $ 55.5 $ 29.8 $ 14.9 $ 164.1 Energy and Capacity Purchase Contracts 90.6 181.7 179.9 282.3 734.5 Total $ 154.5 $ 237.2 $ 209.7 $ 297.2 $ 898.6 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 98.4 $ 139.7 $ 69.7 $ 22.6 $ 330.4 Energy and Capacity Purchase Contracts 32.6 66.6 62.5 175.9 337.6 Total $ 131.0 $ 206.3 $ 132.2 $ 198.5 $ 668.0 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion . 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 December 31, 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 December 31, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 149.7 January 2017 to February 2018 OPCo 0.6 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 approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2016 , SWEPCo has collected approximately $69 million through a rider for final mine closure and reclamation costs, of which $73 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of December 31, 2016, the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2016 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of December 31, 2016 , I&M’s accrual for all of these sites is $7 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $9 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2016 and 2015 , the total decommissioning trust fund balance was $1.9 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the Department of Energy (DOE) through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to zero. As of December 31, 2016 and 2015 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $311 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $6 million , $13 million and $22 million in 2016 , 2015 and 2014 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. In February 2017, the settlement agreement was extended through December 31, 2019. The proceeds reduced costs for dry cask storage. As of December 31, 2016 , I&M has deferred $22 million in Prepayments and Other Current Assets and $5 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Insurance I&M carries insurance coverage in the amount of $3 billion for a nuclear incident at the Cook Plant for decontamination, stabilization and extraordinary incidents caused by premature decommissioning. Insurance coverage for a nonnuclear property incident at the Cook Plant is $1.5 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $50 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident at $13.4 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M was initially covered for public nuclear liability for the first $375 million through commercially available insurance. Beginning in January 2017, the coverage increases to $450 million . The next level of liability coverage of up to $13 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims 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, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement has been reached in the three class actions and the district court issued preliminary approval of that settlement on January 26, 2017. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a tentative settlement was reached for the remaining case, subject to final documentation. Management does not expect the settlement to have a material impact on the financial statements. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and stayed the entire case pending oral argument in March 2017. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2016 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) (b) $ 1,407.8 $ 1,441.6 $ 985.5 $ 371.8 $ 4,206.7 Energy and Capacity Purchase Contracts 215.5 437.1 439.1 1,740.2 2,831.9 Total $ 1,623.3 $ 1,878.7 $ 1,424.6 $ 2,112.0 $ 7,038.6 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 491.5 $ 433.8 $ 415.0 $ 1.2 $ 1,341.5 Energy and Capacity Purchase Contracts 33.4 68.9 72.4 430.7 605.4 Total $ 524.9 $ 502.7 $ 487.4 $ 431.9 $ 1,946.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 292.7 $ 277.8 $ 221.9 $ 266.1 $ 1,058.5 Energy and Capacity Purchase Contracts 118.5 247.7 249.5 497.5 1,113.2 Total $ 411.2 $ 525.5 $ 471.4 $ 763.6 $ 2,171.7 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Total $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 63.9 $ 55.5 $ 29.8 $ 14.9 $ 164.1 Energy and Capacity Purchase Contracts 90.6 181.7 179.9 282.3 734.5 Total $ 154.5 $ 237.2 $ 209.7 $ 297.2 $ 898.6 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 98.4 $ 139.7 $ 69.7 $ 22.6 $ 330.4 Energy and Capacity Purchase Contracts 32.6 66.6 62.5 175.9 337.6 Total $ 131.0 $ 206.3 $ 132.2 $ 198.5 $ 668.0 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion . 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 December 31, 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 December 31, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 149.7 January 2017 to February 2018 OPCo 0.6 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 approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2016 , SWEPCo has collected approximately $69 million through a rider for final mine closure and reclamation costs, of which $73 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of December 31, 2016, the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2016 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of December 31, 2016 , I&M’s accrual for all of these sites is $7 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $9 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2016 and 2015 , the total decommissioning trust fund balance was $1.9 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the Department of Energy (DOE) through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to zero. As of December 31, 2016 and 2015 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $311 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $6 million , $13 million and $22 million in 2016 , 2015 and 2014 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. In February 2017, the settlement agreement was extended through December 31, 2019. The proceeds reduced costs for dry cask storage. As of December 31, 2016 , I&M has deferred $22 million in Prepayments and Other Current Assets and $5 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Insurance I&M carries insurance coverage in the amount of $3 billion for a nuclear incident at the Cook Plant for decontamination, stabilization and extraordinary incidents caused by premature decommissioning. Insurance coverage for a nonnuclear property incident at the Cook Plant is $1.5 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $50 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident at $13.4 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M was initially covered for public nuclear liability for the first $375 million through commercially available insurance. Beginning in January 2017, the coverage increases to $450 million . The next level of liability coverage of up to $13 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims 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, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement has been reached in the three class actions and the district court issued preliminary approval of that settlement on January 26, 2017. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a tentative settlement was reached for the remaining case, subject to final documentation. Management does not expect the settlement to have a material impact on the financial statements. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and stayed the entire case pending oral argument in March 2017. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Ohio Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2016 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) (b) $ 1,407.8 $ 1,441.6 $ 985.5 $ 371.8 $ 4,206.7 Energy and Capacity Purchase Contracts 215.5 437.1 439.1 1,740.2 2,831.9 Total $ 1,623.3 $ 1,878.7 $ 1,424.6 $ 2,112.0 $ 7,038.6 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 491.5 $ 433.8 $ 415.0 $ 1.2 $ 1,341.5 Energy and Capacity Purchase Contracts 33.4 68.9 72.4 430.7 605.4 Total $ 524.9 $ 502.7 $ 487.4 $ 431.9 $ 1,946.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 292.7 $ 277.8 $ 221.9 $ 266.1 $ 1,058.5 Energy and Capacity Purchase Contracts 118.5 247.7 249.5 497.5 1,113.2 Total $ 411.2 $ 525.5 $ 471.4 $ 763.6 $ 2,171.7 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Total $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 63.9 $ 55.5 $ 29.8 $ 14.9 $ 164.1 Energy and Capacity Purchase Contracts 90.6 181.7 179.9 282.3 734.5 Total $ 154.5 $ 237.2 $ 209.7 $ 297.2 $ 898.6 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 98.4 $ 139.7 $ 69.7 $ 22.6 $ 330.4 Energy and Capacity Purchase Contracts 32.6 66.6 62.5 175.9 337.6 Total $ 131.0 $ 206.3 $ 132.2 $ 198.5 $ 668.0 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion . 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 December 31, 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 December 31, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 149.7 January 2017 to February 2018 OPCo 0.6 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 approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2016 , SWEPCo has collected approximately $69 million through a rider for final mine closure and reclamation costs, of which $73 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of December 31, 2016, the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2016 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of December 31, 2016 , I&M’s accrual for all of these sites is $7 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $9 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2016 and 2015 , the total decommissioning trust fund balance was $1.9 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the Department of Energy (DOE) through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to zero. As of December 31, 2016 and 2015 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $311 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $6 million , $13 million and $22 million in 2016 , 2015 and 2014 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. In February 2017, the settlement agreement was extended through December 31, 2019. The proceeds reduced costs for dry cask storage. As of December 31, 2016 , I&M has deferred $22 million in Prepayments and Other Current Assets and $5 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Insurance I&M carries insurance coverage in the amount of $3 billion for a nuclear incident at the Cook Plant for decontamination, stabilization and extraordinary incidents caused by premature decommissioning. Insurance coverage for a nonnuclear property incident at the Cook Plant is $1.5 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $50 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident at $13.4 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M was initially covered for public nuclear liability for the first $375 million through commercially available insurance. Beginning in January 2017, the coverage increases to $450 million . The next level of liability coverage of up to $13 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims 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, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement has been reached in the three class actions and the district court issued preliminary approval of that settlement on January 26, 2017. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a tentative settlement was reached for the remaining case, subject to final documentation. Management does not expect the settlement to have a material impact on the financial statements. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and stayed the entire case pending oral argument in March 2017. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Public Service Co Of Oklahoma [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2016 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) (b) $ 1,407.8 $ 1,441.6 $ 985.5 $ 371.8 $ 4,206.7 Energy and Capacity Purchase Contracts 215.5 437.1 439.1 1,740.2 2,831.9 Total $ 1,623.3 $ 1,878.7 $ 1,424.6 $ 2,112.0 $ 7,038.6 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 491.5 $ 433.8 $ 415.0 $ 1.2 $ 1,341.5 Energy and Capacity Purchase Contracts 33.4 68.9 72.4 430.7 605.4 Total $ 524.9 $ 502.7 $ 487.4 $ 431.9 $ 1,946.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 292.7 $ 277.8 $ 221.9 $ 266.1 $ 1,058.5 Energy and Capacity Purchase Contracts 118.5 247.7 249.5 497.5 1,113.2 Total $ 411.2 $ 525.5 $ 471.4 $ 763.6 $ 2,171.7 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Total $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 63.9 $ 55.5 $ 29.8 $ 14.9 $ 164.1 Energy and Capacity Purchase Contracts 90.6 181.7 179.9 282.3 734.5 Total $ 154.5 $ 237.2 $ 209.7 $ 297.2 $ 898.6 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 98.4 $ 139.7 $ 69.7 $ 22.6 $ 330.4 Energy and Capacity Purchase Contracts 32.6 66.6 62.5 175.9 337.6 Total $ 131.0 $ 206.3 $ 132.2 $ 198.5 $ 668.0 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion . 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 December 31, 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 December 31, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 149.7 January 2017 to February 2018 OPCo 0.6 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 approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2016 , SWEPCo has collected approximately $69 million through a rider for final mine closure and reclamation costs, of which $73 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of December 31, 2016, the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2016 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of December 31, 2016 , I&M’s accrual for all of these sites is $7 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $9 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2016 and 2015 , the total decommissioning trust fund balance was $1.9 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the Department of Energy (DOE) through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to zero. As of December 31, 2016 and 2015 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $311 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $6 million , $13 million and $22 million in 2016 , 2015 and 2014 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. In February 2017, the settlement agreement was extended through December 31, 2019. The proceeds reduced costs for dry cask storage. As of December 31, 2016 , I&M has deferred $22 million in Prepayments and Other Current Assets and $5 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Insurance I&M carries insurance coverage in the amount of $3 billion for a nuclear incident at the Cook Plant for decontamination, stabilization and extraordinary incidents caused by premature decommissioning. Insurance coverage for a nonnuclear property incident at the Cook Plant is $1.5 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $50 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident at $13.4 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M was initially covered for public nuclear liability for the first $375 million through commercially available insurance. Beginning in January 2017, the coverage increases to $450 million . The next level of liability coverage of up to $13 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims 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, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement has been reached in the three class actions and the district court issued preliminary approval of that settlement on January 26, 2017. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a tentative settlement was reached for the remaining case, subject to final documentation. Management does not expect the settlement to have a material impact on the financial statements. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and stayed the entire case pending oral argument in March 2017. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.
Southwestern Electric Power Co [Member]
Commitments, Guarantees and Contingencies	COMMITMENTS, GUARANTEES AND CONTINGENCIES The disclosures in this note apply to all Registrants unless indicated otherwise. The Registrants are subject to certain claims and legal actions arising in the ordinary course of business. In addition, the Registrants business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation against the Registrants cannot be predicted. Management accrues contingent liabilities only when management concludes that it is both probable that a liability has been incurred at the date of the financial statements and the amount of loss can be reasonably estimated. When management determines that it is not probable, but rather reasonably possible that a liability has been incurred at the date of the financial statements, management discloses such contingencies and the possible loss or range of loss if such estimate can be made. Any estimated range is based on currently available information and involves elements of judgment and significant uncertainties. Any estimated range of possible loss may not represent the maximum possible loss exposure. Circumstances change over time and actual results may vary significantly from estimates. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, AEP subsidiaries contractually commit to third-party construction vendors for certain material purchases and other construction services. Fuel, materials, supplies, services and property, plant and equipment are also purchased under contract as part of the normal course of business. Certain supply contracts contain penalty provisions for early termination. In accordance with the accounting guidance for “Commitments”, the following tables summarize the Registrants’ actual contractual commitments as of December 31, 2016 : Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) (b) $ 1,407.8 $ 1,441.6 $ 985.5 $ 371.8 $ 4,206.7 Energy and Capacity Purchase Contracts 215.5 437.1 439.1 1,740.2 2,831.9 Total $ 1,623.3 $ 1,878.7 $ 1,424.6 $ 2,112.0 $ 7,038.6 Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 491.5 $ 433.8 $ 415.0 $ 1.2 $ 1,341.5 Energy and Capacity Purchase Contracts 33.4 68.9 72.4 430.7 605.4 Total $ 524.9 $ 502.7 $ 487.4 $ 431.9 $ 1,946.9 Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 292.7 $ 277.8 $ 221.9 $ 266.1 $ 1,058.5 Energy and Capacity Purchase Contracts 118.5 247.7 249.5 497.5 1,113.2 Total $ 411.2 $ 525.5 $ 471.4 $ 763.6 $ 2,171.7 Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Total $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 63.9 $ 55.5 $ 29.8 $ 14.9 $ 164.1 Energy and Capacity Purchase Contracts 90.6 181.7 179.9 282.3 734.5 Total $ 154.5 $ 237.2 $ 209.7 $ 297.2 $ 898.6 Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 98.4 $ 139.7 $ 69.7 $ 22.6 $ 330.4 Energy and Capacity Purchase Contracts 32.6 66.6 62.5 175.9 337.6 Total $ 131.0 $ 206.3 $ 132.2 $ 198.5 $ 668.0 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . GUARANTEES Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below. Letters of Credit (Applies to AEP, APCo, I&M and OPCo) Standby letters of credit are entered into with third parties. These letters of credit are issued in the ordinary course of business and cover items such as natural gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves. AEP has two revolving credit facilities totaling $3.5 billion . 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 December 31, 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 December 31, 2016 , the Registrants’ maximum future payments for letters of credit issued under the uncommitted facilities were as follows: Company Amount Maturity (in millions) AEP $ 149.7 January 2017 to February 2018 OPCo 0.6 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 approximately $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of December 31, 2016 , SWEPCo has collected approximately $69 million through a rider for final mine closure and reclamation costs, of which $73 million is recorded in Asset Retirement Obligations, offset by $4 million that is recorded in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheet. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause. Guarantees of Equity Method Investees (Applies to AEP) AEP issued a performance guarantee for a 50% owned joint venture which is accounted for as an equity method investment. If the joint venture were to default on payments or performance, AEP would be required to make payments on behalf of the joint venture. As of December 31, 2016, the maximum potential amount of future payments associated with this guarantee was $75 million , which expires in December 2019. Indemnifications and Other Guarantees Contracts The Registrants enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of December 31, 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. Lease Obligations Certain Registrants lease certain equipment under master lease agreements. See “Master Lease Agreements”, “Railcar Lease” and “AEPRO Boat and Barge Leases” sections of Note 13 for disclosure of lease residual value guarantees. ENVIRONMENTAL CONTINGENCIES The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation By-products from the generation of electricity include materials such as ash, slag, sludge, low-level radioactive waste and SNF. Coal combustion by-products, which constitute the overwhelming percentage of these materials, are typically treated and deposited in captive disposal facilities or are beneficially utilized. In addition, the generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. The Registrants currently incur costs to dispose of these substances safely. Superfund addresses clean-up of hazardous substances that are released to the environment. The Federal EPA administers the clean-up programs. Several states enacted similar laws. As of December 31, 2016 , APCo and OPCo are named as a Potentially Responsible Party (PRP) for one site and three sites, respectively, by the Federal EPA for which alleged liability is unresolved. There are nine additional sites for which APCo, I&M, OPCo and SWEPCo received information requests which could lead to PRP designation. I&M has also been named potentially liable at two sites under state law including the I&M site discussed in the next paragraph. In those instances where a PRP or defendant has been named, disposal or recycling activities were in accordance with the then-applicable laws and regulations. Superfund does not recognize compliance as a defense, but imposes strict liability on parties who fall within its broad statutory categories. Liability has been resolved for a number of sites with no significant effect on net income. In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M’s accrual was reduced. As of December 31, 2016 , I&M’s accrual for all of these sites is $7 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. Management evaluates the potential liability for each Superfund site separately, but several general statements can be made about potential future liability. Allegations that materials were disposed at a particular site are often unsubstantiated and the quantity of materials deposited at a site can be small and often nonhazardous. Although Superfund liability has been interpreted by the courts as joint and several, typically many parties are named as PRPs for each site and several of the parties are financially sound enterprises. At present, management’s estimates do not anticipate material cleanup costs for identified Superfund sites, except the I&M sites discussed above. NUCLEAR CONTINGENCIES (APPLIES TO AEP AND I&M) I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission (NRC). I&M has a significant future financial commitment to dispose of SNF and to safely decommission and decontaminate the plant. The licenses to operate the two nuclear units at the Cook Plant expire in 2034 and 2037. The operation of a nuclear facility also involves special risks, potential liabilities and specific regulatory and safety requirements. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The most recent decommissioning cost study was performed in 2015. According to that study, the estimated cost of decommissioning and disposal of low-level radioactive waste is $1.6 billion in 2015 nondiscounted dollars, with additional ongoing costs of $5 million per year for post decommissioning storage of SNF and an eventual cost of $57 million for the subsequent decommissioning of the spent fuel storage facility, also in 2015 nondiscounted dollars. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amounts recovered in rates were $9 million , $9 million and $9 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. Decommissioning costs recovered from customers are deposited in external trusts. As of December 31, 2016 and 2015 , the total decommissioning trust fund balance was $1.9 billion and $1.8 billion , respectively. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future net income and cash flows would be reduced and financial condition could be impacted if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWh for fuel consumed after April 6, 1983 at the Cook Plant was collected from customers and remitted to the Department of Energy (DOE) through May 14, 2014. In May 2014, pursuant to court order from the U.S Court of Appeals for the District of Columbia Circuit, the DOE adjusted the fee to zero. As of December 31, 2016 and 2015 , fees and related interest of $266 million and $266 million , respectively, for fuel consumed prior to April 7, 1983 have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $311 million and $309 million , respectively, to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trusts on the balance sheets. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. In 2011, I&M signed a settlement agreement with the federal government which permits I&M to make annual filings to recover certain SNF storage costs incurred as a result of the government’s delays in accepting SNF for permanent storage. Under the settlement agreement, I&M received $6 million , $13 million and $22 million in 2016 , 2015 and 2014 , respectively, to recover costs and will be eligible to receive additional payment of annual claims for allowed costs that are incurred through December 31, 2016. In February 2017, the settlement agreement was extended through December 31, 2019. The proceeds reduced costs for dry cask storage. As of December 31, 2016 , I&M has deferred $22 million in Prepayments and Other Current Assets and $5 million in Deferred Charges and Other Noncurrent Assets on the balance sheet of dry cask storage and related operation and maintenance costs for recovery under this agreement. See “Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal” section of Note 11 for disclosure of the fair value of assets within the trusts. Nuclear Insurance I&M carries insurance coverage in the amount of $3 billion for a nuclear incident at the Cook Plant for decontamination, stabilization and extraordinary incidents caused by premature decommissioning. Insurance coverage for a nonnuclear property incident at the Cook Plant is $1.5 billion . Additional insurance provides coverage for a weekly indemnity payment resulting from an insured accidental outage. I&M utilizes industry mutual insurers for the placement of this insurance coverage. Coverage from these industry mutual insurance programs require a contingent financial obligation of up to $50 million for I&M, which is assessable if the insurer’s financial resources would be inadequate to pay for industry losses. The Price-Anderson Act, extended through December 31, 2025, establishes insurance protection for public nuclear liability arising from a nuclear incident at $13.4 billion and applies to any incident at a licensed reactor in the U.S. Commercially available insurance, which must be carried for each licensed reactor, provides $375 million of coverage. In the event of a nuclear incident at any nuclear plant in the U.S., the remainder of the liability would be provided by a deferred premium assessment of $127 million on each licensed reactor in the U.S. payable in annual installments of $19 million . As a result, I&M could be assessed $255 million per nuclear incident payable in annual installments of $38 million . The number of incidents for which payments could be required is not limited. In the event of an incident of a catastrophic nature, I&M was initially covered for public nuclear liability for the first $375 million through commercially available insurance. Beginning in January 2017, the coverage increases to $450 million . The next level of liability coverage of up to $13 billion would be covered by claim premium assessments made under the Price-Anderson Act. In the event nuclear losses or liabilities are underinsured or exceed accumulated funds, I&M would seek recovery of those amounts from customers through rate increase. If recovery from customers is not possible, it could reduce future net income and cash flows and impact financial condition. OPERATIONAL CONTINGENCIES Insurance and Potential Losses The Registrants maintain insurance coverage normal and customary for electric utilities, subject to various deductibles. The Registrants also maintain property and casualty insurance that may cover certain physical damage or third-party injuries caused by cyber security incidents. Insurance coverage includes all risks of physical loss or damage to nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. The insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by the Registrants. Coverage is generally provided by a combination of the protected cell of EIS and/or various industry mutual and/or commercial insurance carriers. See “Nuclear Contingencies” section of this footnote for a discussion of I&M’s nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to a cyber security incident or damage to the Cook Plant and costs of replacement power in the event of an incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could reduce future net income and cash flows and impact financial condition. Rockport Plant Litigation (Applies to AEP and I&M) In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCo and I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 lease expiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment, repowering or retirement of the unit. The plaintiff further alleges that the defendants’ actions constitute breach of the lease and participation agreement. The plaintiff seeks a judgment declaring that the defendants breached the lease, must satisfy obligations related to installation of emission control equipment and indemnify the plaintiff. The New York court granted a motion to transfer this case to the U.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiff’s claims. Several claims 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, a lawsuit was commenced in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP is among the companies named as defendants in some of these cases. AEP settled, received summary judgment or was dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court’s dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court’s orders in these cases. The United States Supreme Court affirmed the U.S. Court of Appeals for the Ninth Circuit’s opinion. The cases were remanded to the district court for further proceedings. AEP had four pending cases, of which three are class actions and one is a single plaintiff case. A settlement has been reached in the three class actions and the district court issued preliminary approval of that settlement on January 26, 2017. In May 2016, the district court dismissed the remaining case. In December 2016, the plaintiff appealed the dismissal to the U.S. Court of Appeals for the Ninth Circuit. In February 2017, a tentative settlement was reached for the remaining case, subject to final documentation. Management does not expect the settlement to have a material impact on the financial statements. Gavin Landfill Litigation (Applies to AEP and OPCo) In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. As a result of OPCo transferring its generation assets to AGR, the outcome of this complaint will be the responsibility of AGR. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Twelve of the family members are pursuing personal injury/illness claims (non-working direct claims) and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, defendants filed a motion to dismiss the complaint, contending the case should be filed in Ohio. In August 2015, the court denied the motion. Defendants appealed that decision to the West Virginia Supreme Court. In February 2016, a decision was issued by the court denying the appeal and remanding the case to the West Virginia Mass Litigation Panel (WVMLP), rather than back to the Mason County, West Virginia Circuit Court. Defendants’ subsequently filed a motion to dismiss the twelve non-working direct claims under Ohio law. The WVMLP denied the motion and defendants again appealed to the West Virginia Supreme Court. The West Virginia Supreme Court granted the appeal of the twelve non-working direct claims and stayed the entire case pending oral argument in March 2017. Management will continue to defend against the claims and believes the provision recorded is adequate. Management is unable to determine a range of potential additional losses that are reasonably possible of occurring.

Dispositions, Assets and Liabil

Dispositions, Assets and Liabilities Held for Sale and Impairments	12 Months Ended
	Dec. 31, 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 all Registrants 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 did not record a gain or loss related to this sale and will address recovery of Tanners Creek deferred costs in future rate proceedings. If any of the costs associated with Tanners 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 income. The cash paid was recorded in Operating Activities on the statements of cash flows. AEPRO (Corporate and Other) 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 had a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2019. Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015 and 2014 , as shown in the following table: Years Ended December 31, 2015 2014 (in millions) Other Revenues $ 447.1 $ 641.6 Other Operation Expense 321.3 459.5 Maintenance Expense 21.5 32.6 Depreciation and Amortization Expense 26.9 31.5 Taxes Other Than Income Taxes 10.6 14.2 Total Expenses 380.3 537.8 Other Income (Expense) (16.9 ) (17.1 ) Pretax Income of Discontinued Operations 49.9 86.7 Income Tax Expense 19.4 39.0 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) Income from Discontinued Operations of AEPRO 30.4 47.5 Gain on Sale of Discontinued Operations 240.1 — Income Tax Expense (Benefit) (13.2 ) — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 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 income. ASSETS AND LIABILITIES HELD FOR SALE 2016 Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,329 MWs of competitive generation assets for approximately $2.2 billion to a nonaffiliated party. The sale closed in January 2017 . In the third quarter of 2016, management determined the disposal group met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. The Income from Continuing Operations before Income Tax Expense (Credit) and Equity Earnings of the four plants was approximately $375 million , $451 million and $444 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. December 31, 2016 Assets: (in millions) Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9 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 and 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 statements of income. 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. Based on capital expenditure activity of the Merchant Coal-fired Generation Assets in the fourth quarter of 2016, AEP recorded a pretax impairment of an additional $3 million in Asset Impairments and Other Related Charges on AEP’s statements of income.
Appalachian Power Co [Member]
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 all Registrants 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 did not record a gain or loss related to this sale and will address recovery of Tanners Creek deferred costs in future rate proceedings. If any of the costs associated with Tanners 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 income. The cash paid was recorded in Operating Activities on the statements of cash flows. AEPRO (Corporate and Other) 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 had a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2019. Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015 and 2014 , as shown in the following table: Years Ended December 31, 2015 2014 (in millions) Other Revenues $ 447.1 $ 641.6 Other Operation Expense 321.3 459.5 Maintenance Expense 21.5 32.6 Depreciation and Amortization Expense 26.9 31.5 Taxes Other Than Income Taxes 10.6 14.2 Total Expenses 380.3 537.8 Other Income (Expense) (16.9 ) (17.1 ) Pretax Income of Discontinued Operations 49.9 86.7 Income Tax Expense 19.4 39.0 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) Income from Discontinued Operations of AEPRO 30.4 47.5 Gain on Sale of Discontinued Operations 240.1 — Income Tax Expense (Benefit) (13.2 ) — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 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 income. ASSETS AND LIABILITIES HELD FOR SALE 2016 Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,329 MWs of competitive generation assets for approximately $2.2 billion to a nonaffiliated party. The sale closed in January 2017 . In the third quarter of 2016, management determined the disposal group met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. The Income from Continuing Operations before Income Tax Expense (Credit) and Equity Earnings of the four plants was approximately $375 million , $451 million and $444 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. December 31, 2016 Assets: (in millions) Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9 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 and 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 statements of income. 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. Based on capital expenditure activity of the Merchant Coal-fired Generation Assets in the fourth quarter of 2016, AEP recorded a pretax impairment of an additional $3 million in Asset Impairments and Other Related Charges on AEP’s statements of income.
Indiana Michigan Power Co [Member]
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 all Registrants 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 did not record a gain or loss related to this sale and will address recovery of Tanners Creek deferred costs in future rate proceedings. If any of the costs associated with Tanners 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 income. The cash paid was recorded in Operating Activities on the statements of cash flows. AEPRO (Corporate and Other) 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 had a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2019. Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015 and 2014 , as shown in the following table: Years Ended December 31, 2015 2014 (in millions) Other Revenues $ 447.1 $ 641.6 Other Operation Expense 321.3 459.5 Maintenance Expense 21.5 32.6 Depreciation and Amortization Expense 26.9 31.5 Taxes Other Than Income Taxes 10.6 14.2 Total Expenses 380.3 537.8 Other Income (Expense) (16.9 ) (17.1 ) Pretax Income of Discontinued Operations 49.9 86.7 Income Tax Expense 19.4 39.0 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) Income from Discontinued Operations of AEPRO 30.4 47.5 Gain on Sale of Discontinued Operations 240.1 — Income Tax Expense (Benefit) (13.2 ) — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 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 income. ASSETS AND LIABILITIES HELD FOR SALE 2016 Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,329 MWs of competitive generation assets for approximately $2.2 billion to a nonaffiliated party. The sale closed in January 2017 . In the third quarter of 2016, management determined the disposal group met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. The Income from Continuing Operations before Income Tax Expense (Credit) and Equity Earnings of the four plants was approximately $375 million , $451 million and $444 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. December 31, 2016 Assets: (in millions) Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9 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 and 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 statements of income. 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. Based on capital expenditure activity of the Merchant Coal-fired Generation Assets in the fourth quarter of 2016, AEP recorded a pretax impairment of an additional $3 million in Asset Impairments and Other Related Charges on AEP’s statements of income.
Ohio Power Co [Member]
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 all Registrants 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 did not record a gain or loss related to this sale and will address recovery of Tanners Creek deferred costs in future rate proceedings. If any of the costs associated with Tanners 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 income. The cash paid was recorded in Operating Activities on the statements of cash flows. AEPRO (Corporate and Other) 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 had a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2019. Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015 and 2014 , as shown in the following table: Years Ended December 31, 2015 2014 (in millions) Other Revenues $ 447.1 $ 641.6 Other Operation Expense 321.3 459.5 Maintenance Expense 21.5 32.6 Depreciation and Amortization Expense 26.9 31.5 Taxes Other Than Income Taxes 10.6 14.2 Total Expenses 380.3 537.8 Other Income (Expense) (16.9 ) (17.1 ) Pretax Income of Discontinued Operations 49.9 86.7 Income Tax Expense 19.4 39.0 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) Income from Discontinued Operations of AEPRO 30.4 47.5 Gain on Sale of Discontinued Operations 240.1 — Income Tax Expense (Benefit) (13.2 ) — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 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 income. ASSETS AND LIABILITIES HELD FOR SALE 2016 Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,329 MWs of competitive generation assets for approximately $2.2 billion to a nonaffiliated party. The sale closed in January 2017 . In the third quarter of 2016, management determined the disposal group met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. The Income from Continuing Operations before Income Tax Expense (Credit) and Equity Earnings of the four plants was approximately $375 million , $451 million and $444 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. December 31, 2016 Assets: (in millions) Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9 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 and 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 statements of income. 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. Based on capital expenditure activity of the Merchant Coal-fired Generation Assets in the fourth quarter of 2016, AEP recorded a pretax impairment of an additional $3 million in Asset Impairments and Other Related Charges on AEP’s statements of income.
Public Service Co Of Oklahoma [Member]
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 all Registrants 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 did not record a gain or loss related to this sale and will address recovery of Tanners Creek deferred costs in future rate proceedings. If any of the costs associated with Tanners 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 income. The cash paid was recorded in Operating Activities on the statements of cash flows. AEPRO (Corporate and Other) 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 had a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2019. Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015 and 2014 , as shown in the following table: Years Ended December 31, 2015 2014 (in millions) Other Revenues $ 447.1 $ 641.6 Other Operation Expense 321.3 459.5 Maintenance Expense 21.5 32.6 Depreciation and Amortization Expense 26.9 31.5 Taxes Other Than Income Taxes 10.6 14.2 Total Expenses 380.3 537.8 Other Income (Expense) (16.9 ) (17.1 ) Pretax Income of Discontinued Operations 49.9 86.7 Income Tax Expense 19.4 39.0 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) Income from Discontinued Operations of AEPRO 30.4 47.5 Gain on Sale of Discontinued Operations 240.1 — Income Tax Expense (Benefit) (13.2 ) — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 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 income. ASSETS AND LIABILITIES HELD FOR SALE 2016 Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,329 MWs of competitive generation assets for approximately $2.2 billion to a nonaffiliated party. The sale closed in January 2017 . In the third quarter of 2016, management determined the disposal group met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. The Income from Continuing Operations before Income Tax Expense (Credit) and Equity Earnings of the four plants was approximately $375 million , $451 million and $444 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. December 31, 2016 Assets: (in millions) Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9 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 and 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 statements of income. 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. Based on capital expenditure activity of the Merchant Coal-fired Generation Assets in the fourth quarter of 2016, AEP recorded a pretax impairment of an additional $3 million in Asset Impairments and Other Related Charges on AEP’s statements of income.
Southwestern Electric Power Co [Member]
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 all Registrants 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 did not record a gain or loss related to this sale and will address recovery of Tanners Creek deferred costs in future rate proceedings. If any of the costs associated with Tanners 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 income. The cash paid was recorded in Operating Activities on the statements of cash flows. AEPRO (Corporate and Other) 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 had a separate contract with the nonaffiliated party to barge coal for AGR. These agreements with the nonaffiliated party extend through the end of 2019. Results of operations of AEPRO have been classified as discontinued operations on AEP’s statements of income for the years ended December 31, 2015 and 2014 , as shown in the following table: Years Ended December 31, 2015 2014 (in millions) Other Revenues $ 447.1 $ 641.6 Other Operation Expense 321.3 459.5 Maintenance Expense 21.5 32.6 Depreciation and Amortization Expense 26.9 31.5 Taxes Other Than Income Taxes 10.6 14.2 Total Expenses 380.3 537.8 Other Income (Expense) (16.9 ) (17.1 ) Pretax Income of Discontinued Operations 49.9 86.7 Income Tax Expense 19.4 39.0 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) Income from Discontinued Operations of AEPRO 30.4 47.5 Gain on Sale of Discontinued Operations 240.1 — Income Tax Expense (Benefit) (13.2 ) — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5 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 income. ASSETS AND LIABILITIES HELD FOR SALE 2016 Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment) In September 2016, AEP signed a Purchase and Sale Agreement to sell AGR’s Gavin, Waterford and Darby plants as well as AEGCo’s Lawrenceburg plant totaling 5,329 MWs of competitive generation assets for approximately $2.2 billion to a nonaffiliated party. The sale closed in January 2017 . In the third quarter of 2016, management determined the disposal group met the classification of held for sale. Accordingly, the four plants’ assets and liabilities have been recorded as Assets Held for Sale and Liabilities Held for Sale on AEP’s balance sheet as of December 31, 2016 and as shown in the table below. The Income from Continuing Operations before Income Tax Expense (Credit) and Equity Earnings of the four plants was approximately $375 million , $451 million and $444 million for the years ended December 31, 2016 , 2015 and 2014 , respectively. December 31, 2016 Assets: (in millions) Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9 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 and 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 statements of income. 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. Based on capital expenditure activity of the Merchant Coal-fired Generation Assets in the fourth quarter of 2016, AEP recorded a pretax impairment of an additional $3 million in Asset Impairments and Other Related Charges on AEP’s statements of income.

Benefit Plans

Benefit Plans	12 Months Ended
	Dec. 31, 2016
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2016 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions used for OPEB plans measurement purposes are shown below: January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2016 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Service Cost 85.8 93.5 10.2 12.2 Interest Cost 211.6 205.3 60.9 56.8 Actuarial (Gain) Loss 142.7 (200.6 ) 17.3 37.2 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Participant Contributions — — 37.8 33.3 Medicare Subsidy — — 0.8 0.8 Benefit Obligation as of December 31, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Actual Gain (Loss) on Plan Assets 315.5 32.4 56.0 (34.0 ) Company Contributions 91.4 97.9 4.9 12.9 Participant Contributions — — 37.8 33.3 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Fair Value of Plan Assets as of December 31, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Funded (Underfunded) Status as of December 31, $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Service Cost 8.1 8.7 1.0 1.1 Interest Cost 27.2 26.7 10.8 10.3 Actuarial (Gain) Loss 9.2 (41.4 ) (0.2 ) 2.5 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Participant Contributions — — 6.4 5.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Actual Gain (Loss) on Plan Assets 38.3 (5.7 ) 5.9 (7.7 ) Company Contributions 8.8 10.0 2.7 2.8 Participant Contributions — — 6.4 5.7 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Fair Value of Plan Assets as of December 31, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Underfunded Status as of December 31, $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Service Cost 12.2 12.9 1.5 1.6 Interest Cost 25.3 24.5 7.0 6.4 Actuarial (Gain) Loss 20.1 (28.4 ) 3.8 7.7 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Participant Contributions — — 4.6 4.0 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Actual Gain (Loss) on Plan Assets 40.6 (0.9 ) 8.7 (2.3 ) Company Contributions 13.0 14.6 — 0.1 Participant Contributions — — 4.6 4.0 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Fair Value of Plan Assets as of December 31, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Funded (Underfunded) Status as of December 31, $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Service Cost 6.5 6.7 0.8 0.9 Interest Cost 20.6 20.3 7.0 6.4 Actuarial (Gain) Loss 4.7 (19.5 ) (1.0 ) 8.7 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Participant Contributions — — 4.7 4.3 Medicare Subsidy — — 0.1 (0.1 ) Benefit Obligation as of December 31, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Actual Gain (Loss) on Plan Assets 30.9 2.2 2.5 (2.6 ) Company Contributions 7.2 7.7 — — Participant Contributions — — 4.7 4.3 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Fair Value of Plan Assets as of December 31, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Funded (Underfunded) Status as of December 31, $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Service Cost 6.2 6.4 0.6 0.7 Interest Cost 11.2 10.9 3.3 3.0 Actuarial (Gain) Loss 3.1 (17.9 ) 1.0 2.4 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Participant Contributions — — 2.2 1.9 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Actual Gain (Loss) on Plan Assets 17.3 0.1 3.1 (2.5 ) Company Contributions 5.8 5.9 — — Participant Contributions — — 2.2 1.9 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Fair Value of Plan Assets as of December 31, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Funded (Underfunded) Status as of December 31, $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Service Cost 8.1 8.3 0.8 0.8 Interest Cost 12.4 11.8 3.6 3.4 Actuarial (Gain) Loss 13.8 (16.2 ) 1.5 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Participant Contributions — — 2.4 2.1 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Actual Gain (Loss) on Plan Assets 18.8 1.6 4.1 (3.3 ) Company Contributions 8.4 8.1 — — Participant Contributions — — 2.4 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Funded (Underfunded) Status as of December 31, $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Recognized on the Balance Sheets Pension Plans Other Postretirement Benefit Plans December 31, AEP 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 154.5 $ 185.8 Other Current Liabilities – Accrued Short-term Benefit Liability (5.9 ) (6.3 ) (3.0 ) (3.3 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (252.6 ) (219.0 ) (53.0 ) (55.7 ) Funded (Underfunded) Status $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.2 $ 30.8 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.4 ) (2.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (47.6 ) (50.2 ) (31.5 ) (33.7 ) Underfunded Status $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) Pension Plans Other Postretirement Benefit Plans December 31, I&M 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 19.0 $ 22.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (25.5 ) (21.5 ) — — Funded (Underfunded) Status $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 18.6 $ 23.0 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.1 ) (25.4 ) — — Funded (Underfunded) Status $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2016 2015 2016 2015 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 1.6 $ — $ 8.8 $ 10.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (3.1 ) — — Funded (Underfunded) Status $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 9.9 $ 11.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.2 ) (2.1 ) — — Funded (Underfunded) Status $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Included in AOCI and Regulatory Assets AEP Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 1,569.8 $ 1,546.1 $ 614.4 $ 577.4 Prior Service Cost (Credit) 1.0 3.3 (485.4 ) (554.4 ) Recorded as Regulatory Assets $ 1,415.6 $ 1,385.2 $ 90.4 $ 15.1 Deferred Income Taxes 54.4 57.5 13.5 2.8 Net of Tax AOCI 100.8 106.7 25.1 5.1 APCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 216.2 $ 220.8 $ 92.9 $ 86.9 Prior Service Cost (Credit) 0.2 0.3 (70.5 ) (80.6 ) Recorded as Regulatory Assets $ 213.7 $ 218.3 $ 7.7 $ (0.7 ) Deferred Income Taxes 1.0 1.0 5.1 2.4 Net of Tax AOCI 1.7 1.8 9.6 4.6 I&M Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 133.2 $ 130.0 $ 81.3 $ 77.1 Prior Service Cost (Credit) 0.2 0.3 (66.3 ) (75.7 ) Recorded as Regulatory Assets $ 128.2 $ 125.3 $ 13.7 $ 1.1 Deferred Income Taxes 1.8 1.8 0.5 0.1 Net of Tax AOCI 3.4 3.2 0.8 0.2 OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 215.4 $ 222.0 $ 58.2 $ 52.6 Prior Service Cost (Credit) 0.1 0.2 (48.5 ) (55.4 ) Recorded as Regulatory Assets $ 215.5 $ 222.2 $ 9.7 $ (2.8 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 91.0 $ 94.1 $ 37.3 $ 35.2 Prior Service Cost (Credit) — 0.3 (30.2 ) (34.5 ) Recorded as Regulatory Assets $ 91.0 $ 94.4 $ 7.1 $ 0.7 SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 103.8 $ 97.1 $ 45.4 $ 43.3 Prior Service Cost (Credit) 0.1 0.4 (36.6 ) (41.6 ) Recorded as Regulatory Assets $ 103.9 $ 97.5 $ 5.7 $ 1.2 Deferred Income Taxes — — 1.1 0.2 Net of Tax AOCI — — 2.0 0.3 Components of the change in amounts included in AOCI and Regulatory Assets by Registrant are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 107.5 $ 41.8 $ 68.4 $ 176.3 Amortization of Actuarial Loss (83.8 ) (107.1 ) (31.4 ) (18.8 ) Amortization of Prior Service Credit (Cost) (2.3 ) (2.2 ) 69.0 69.1 Change for the Year Ended December 31, $ 21.4 $ (67.5 ) $ 106.0 $ 226.6 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.2 $ (0.3 ) $ 11.4 $ 24.7 Amortization of Actuarial Loss (10.8 ) (13.9 ) (5.4 ) (3.6 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 10.1 10.0 Change for the Year Ended December 31, $ (4.7 ) $ (14.4 ) $ 16.1 $ 31.1 I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 13.2 $ 4.7 $ 7.9 $ 24.7 Amortization of Actuarial Loss (10.0 ) (12.6 ) (3.7 ) (2.0 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ 3.1 $ (8.1 ) $ 13.6 $ 32.1 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 1.5 $ 5.8 $ 9.4 $ 24.0 Amortization of Actuarial Loss (8.1 ) (10.5 ) (3.8 ) (2.1 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 6.9 7.0 Change for the Year Ended December 31, $ (6.7 ) $ (4.9 ) $ 12.5 $ 28.9 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.3 $ (2.9 ) $ 3.9 $ 10.9 Amortization of Actuarial Loss (4.4 ) (5.7 ) (1.8 ) (1.0 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.2 ) 4.3 4.3 Change for the Year Ended December 31, $ (3.4 ) $ (8.8 ) $ 6.4 $ 14.2 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.5 $ (1.8 ) $ 4.0 $ 12.0 Amortization of Actuarial Loss (4.8 ) (6.0 ) (1.9 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.0 5.2 Change for the Year Ended December 31, $ 6.4 $ (8.1 ) $ 7.1 $ 16.1 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below: Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 354.7 $ — $ — $ — $ 354.7 7.3 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Real Estate Investment Trusts 3.1 — — — 3.1 0.1 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trusts (c) — 16.1 — 369.7 385.8 8.1 % Subtotal – Equities 722.0 31.7 — 369.7 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 34.2 34.2 0.7 % United States Government and Agency Securities (c) — 397.8 — 24.1 421.9 8.9 % Corporate Debt (c) — 1,964.2 — 19.0 1,983.2 41.6 % Foreign Debt (c) — 405.4 0.1 16.0 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed (c) — 15.8 — 7.6 23.4 0.5 % Subtotal – Fixed Income — 2,796.0 0.1 100.9 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents (c) — 1.2 — 47.4 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,091.9 $ 674.5 $ 279.2 $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trusts (b) — 12.6 — 19.0 31.6 2.0 % Subtotal – Equities 949.4 28.2 — 19.0 996.6 63.2 % Fixed Income: Common Collective Trust – Debt (b) — — — 100.9 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 209.4 — 100.9 310.3 19.6 % Trust Owned Life Insurance: International Equities (b) — — — 28.3 28.3 1.8 % United States Bonds (b) — — — 184.3 184.3 11.7 % Subtotal – Trust Owned Life Insurance — — — 212.6 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 244.8 $ — $ 338.3 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2017 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 85.8 $ 93.5 $ 71.9 $ 10.2 $ 12.2 $ 14.2 Interest Cost 211.6 205.3 221.0 60.9 56.8 67.2 Expected Return on Plan Assets (280.3 ) (274.8 ) (261.6 ) (107.0 ) (111.0 ) (111.3 ) Amortization of Prior Service
Appalachian Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2016 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions used for OPEB plans measurement purposes are shown below: January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2016 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Service Cost 85.8 93.5 10.2 12.2 Interest Cost 211.6 205.3 60.9 56.8 Actuarial (Gain) Loss 142.7 (200.6 ) 17.3 37.2 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Participant Contributions — — 37.8 33.3 Medicare Subsidy — — 0.8 0.8 Benefit Obligation as of December 31, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Actual Gain (Loss) on Plan Assets 315.5 32.4 56.0 (34.0 ) Company Contributions 91.4 97.9 4.9 12.9 Participant Contributions — — 37.8 33.3 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Fair Value of Plan Assets as of December 31, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Funded (Underfunded) Status as of December 31, $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Service Cost 8.1 8.7 1.0 1.1 Interest Cost 27.2 26.7 10.8 10.3 Actuarial (Gain) Loss 9.2 (41.4 ) (0.2 ) 2.5 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Participant Contributions — — 6.4 5.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Actual Gain (Loss) on Plan Assets 38.3 (5.7 ) 5.9 (7.7 ) Company Contributions 8.8 10.0 2.7 2.8 Participant Contributions — — 6.4 5.7 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Fair Value of Plan Assets as of December 31, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Underfunded Status as of December 31, $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Service Cost 12.2 12.9 1.5 1.6 Interest Cost 25.3 24.5 7.0 6.4 Actuarial (Gain) Loss 20.1 (28.4 ) 3.8 7.7 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Participant Contributions — — 4.6 4.0 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Actual Gain (Loss) on Plan Assets 40.6 (0.9 ) 8.7 (2.3 ) Company Contributions 13.0 14.6 — 0.1 Participant Contributions — — 4.6 4.0 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Fair Value of Plan Assets as of December 31, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Funded (Underfunded) Status as of December 31, $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Service Cost 6.5 6.7 0.8 0.9 Interest Cost 20.6 20.3 7.0 6.4 Actuarial (Gain) Loss 4.7 (19.5 ) (1.0 ) 8.7 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Participant Contributions — — 4.7 4.3 Medicare Subsidy — — 0.1 (0.1 ) Benefit Obligation as of December 31, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Actual Gain (Loss) on Plan Assets 30.9 2.2 2.5 (2.6 ) Company Contributions 7.2 7.7 — — Participant Contributions — — 4.7 4.3 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Fair Value of Plan Assets as of December 31, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Funded (Underfunded) Status as of December 31, $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Service Cost 6.2 6.4 0.6 0.7 Interest Cost 11.2 10.9 3.3 3.0 Actuarial (Gain) Loss 3.1 (17.9 ) 1.0 2.4 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Participant Contributions — — 2.2 1.9 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Actual Gain (Loss) on Plan Assets 17.3 0.1 3.1 (2.5 ) Company Contributions 5.8 5.9 — — Participant Contributions — — 2.2 1.9 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Fair Value of Plan Assets as of December 31, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Funded (Underfunded) Status as of December 31, $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Service Cost 8.1 8.3 0.8 0.8 Interest Cost 12.4 11.8 3.6 3.4 Actuarial (Gain) Loss 13.8 (16.2 ) 1.5 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Participant Contributions — — 2.4 2.1 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Actual Gain (Loss) on Plan Assets 18.8 1.6 4.1 (3.3 ) Company Contributions 8.4 8.1 — — Participant Contributions — — 2.4 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Funded (Underfunded) Status as of December 31, $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Recognized on the Balance Sheets Pension Plans Other Postretirement Benefit Plans December 31, AEP 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 154.5 $ 185.8 Other Current Liabilities – Accrued Short-term Benefit Liability (5.9 ) (6.3 ) (3.0 ) (3.3 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (252.6 ) (219.0 ) (53.0 ) (55.7 ) Funded (Underfunded) Status $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.2 $ 30.8 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.4 ) (2.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (47.6 ) (50.2 ) (31.5 ) (33.7 ) Underfunded Status $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) Pension Plans Other Postretirement Benefit Plans December 31, I&M 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 19.0 $ 22.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (25.5 ) (21.5 ) — — Funded (Underfunded) Status $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 18.6 $ 23.0 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.1 ) (25.4 ) — — Funded (Underfunded) Status $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2016 2015 2016 2015 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 1.6 $ — $ 8.8 $ 10.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (3.1 ) — — Funded (Underfunded) Status $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 9.9 $ 11.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.2 ) (2.1 ) — — Funded (Underfunded) Status $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Included in AOCI and Regulatory Assets AEP Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 1,569.8 $ 1,546.1 $ 614.4 $ 577.4 Prior Service Cost (Credit) 1.0 3.3 (485.4 ) (554.4 ) Recorded as Regulatory Assets $ 1,415.6 $ 1,385.2 $ 90.4 $ 15.1 Deferred Income Taxes 54.4 57.5 13.5 2.8 Net of Tax AOCI 100.8 106.7 25.1 5.1 APCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 216.2 $ 220.8 $ 92.9 $ 86.9 Prior Service Cost (Credit) 0.2 0.3 (70.5 ) (80.6 ) Recorded as Regulatory Assets $ 213.7 $ 218.3 $ 7.7 $ (0.7 ) Deferred Income Taxes 1.0 1.0 5.1 2.4 Net of Tax AOCI 1.7 1.8 9.6 4.6 I&M Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 133.2 $ 130.0 $ 81.3 $ 77.1 Prior Service Cost (Credit) 0.2 0.3 (66.3 ) (75.7 ) Recorded as Regulatory Assets $ 128.2 $ 125.3 $ 13.7 $ 1.1 Deferred Income Taxes 1.8 1.8 0.5 0.1 Net of Tax AOCI 3.4 3.2 0.8 0.2 OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 215.4 $ 222.0 $ 58.2 $ 52.6 Prior Service Cost (Credit) 0.1 0.2 (48.5 ) (55.4 ) Recorded as Regulatory Assets $ 215.5 $ 222.2 $ 9.7 $ (2.8 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 91.0 $ 94.1 $ 37.3 $ 35.2 Prior Service Cost (Credit) — 0.3 (30.2 ) (34.5 ) Recorded as Regulatory Assets $ 91.0 $ 94.4 $ 7.1 $ 0.7 SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 103.8 $ 97.1 $ 45.4 $ 43.3 Prior Service Cost (Credit) 0.1 0.4 (36.6 ) (41.6 ) Recorded as Regulatory Assets $ 103.9 $ 97.5 $ 5.7 $ 1.2 Deferred Income Taxes — — 1.1 0.2 Net of Tax AOCI — — 2.0 0.3 Components of the change in amounts included in AOCI and Regulatory Assets by Registrant are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 107.5 $ 41.8 $ 68.4 $ 176.3 Amortization of Actuarial Loss (83.8 ) (107.1 ) (31.4 ) (18.8 ) Amortization of Prior Service Credit (Cost) (2.3 ) (2.2 ) 69.0 69.1 Change for the Year Ended December 31, $ 21.4 $ (67.5 ) $ 106.0 $ 226.6 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.2 $ (0.3 ) $ 11.4 $ 24.7 Amortization of Actuarial Loss (10.8 ) (13.9 ) (5.4 ) (3.6 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 10.1 10.0 Change for the Year Ended December 31, $ (4.7 ) $ (14.4 ) $ 16.1 $ 31.1 I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 13.2 $ 4.7 $ 7.9 $ 24.7 Amortization of Actuarial Loss (10.0 ) (12.6 ) (3.7 ) (2.0 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ 3.1 $ (8.1 ) $ 13.6 $ 32.1 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 1.5 $ 5.8 $ 9.4 $ 24.0 Amortization of Actuarial Loss (8.1 ) (10.5 ) (3.8 ) (2.1 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 6.9 7.0 Change for the Year Ended December 31, $ (6.7 ) $ (4.9 ) $ 12.5 $ 28.9 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.3 $ (2.9 ) $ 3.9 $ 10.9 Amortization of Actuarial Loss (4.4 ) (5.7 ) (1.8 ) (1.0 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.2 ) 4.3 4.3 Change for the Year Ended December 31, $ (3.4 ) $ (8.8 ) $ 6.4 $ 14.2 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.5 $ (1.8 ) $ 4.0 $ 12.0 Amortization of Actuarial Loss (4.8 ) (6.0 ) (1.9 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.0 5.2 Change for the Year Ended December 31, $ 6.4 $ (8.1 ) $ 7.1 $ 16.1 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below: Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 354.7 $ — $ — $ — $ 354.7 7.3 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Real Estate Investment Trusts 3.1 — — — 3.1 0.1 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trusts (c) — 16.1 — 369.7 385.8 8.1 % Subtotal – Equities 722.0 31.7 — 369.7 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 34.2 34.2 0.7 % United States Government and Agency Securities (c) — 397.8 — 24.1 421.9 8.9 % Corporate Debt (c) — 1,964.2 — 19.0 1,983.2 41.6 % Foreign Debt (c) — 405.4 0.1 16.0 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed (c) — 15.8 — 7.6 23.4 0.5 % Subtotal – Fixed Income — 2,796.0 0.1 100.9 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents (c) — 1.2 — 47.4 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,091.9 $ 674.5 $ 279.2 $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trusts (b) — 12.6 — 19.0 31.6 2.0 % Subtotal – Equities 949.4 28.2 — 19.0 996.6 63.2 % Fixed Income: Common Collective Trust – Debt (b) — — — 100.9 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 209.4 — 100.9 310.3 19.6 % Trust Owned Life Insurance: International Equities (b) — — — 28.3 28.3 1.8 % United States Bonds (b) — — — 184.3 184.3 11.7 % Subtotal – Trust Owned Life Insurance — — — 212.6 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 244.8 $ — $ 338.3 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2017 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 85.8 $ 93.5 $ 71.9 $ 10.2 $ 12.2 $ 14.2 Interest Cost 211.6 205.3 221.0 60.9 56.8 67.2 Expected Return on Plan Assets (280.3 ) (274.8 ) (261.6 ) (107.0 ) (111.0 ) (111.3 ) Amortization of Prior Service
Indiana Michigan Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2016 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions used for OPEB plans measurement purposes are shown below: January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2016 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Service Cost 85.8 93.5 10.2 12.2 Interest Cost 211.6 205.3 60.9 56.8 Actuarial (Gain) Loss 142.7 (200.6 ) 17.3 37.2 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Participant Contributions — — 37.8 33.3 Medicare Subsidy — — 0.8 0.8 Benefit Obligation as of December 31, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Actual Gain (Loss) on Plan Assets 315.5 32.4 56.0 (34.0 ) Company Contributions 91.4 97.9 4.9 12.9 Participant Contributions — — 37.8 33.3 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Fair Value of Plan Assets as of December 31, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Funded (Underfunded) Status as of December 31, $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Service Cost 8.1 8.7 1.0 1.1 Interest Cost 27.2 26.7 10.8 10.3 Actuarial (Gain) Loss 9.2 (41.4 ) (0.2 ) 2.5 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Participant Contributions — — 6.4 5.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Actual Gain (Loss) on Plan Assets 38.3 (5.7 ) 5.9 (7.7 ) Company Contributions 8.8 10.0 2.7 2.8 Participant Contributions — — 6.4 5.7 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Fair Value of Plan Assets as of December 31, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Underfunded Status as of December 31, $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Service Cost 12.2 12.9 1.5 1.6 Interest Cost 25.3 24.5 7.0 6.4 Actuarial (Gain) Loss 20.1 (28.4 ) 3.8 7.7 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Participant Contributions — — 4.6 4.0 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Actual Gain (Loss) on Plan Assets 40.6 (0.9 ) 8.7 (2.3 ) Company Contributions 13.0 14.6 — 0.1 Participant Contributions — — 4.6 4.0 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Fair Value of Plan Assets as of December 31, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Funded (Underfunded) Status as of December 31, $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Service Cost 6.5 6.7 0.8 0.9 Interest Cost 20.6 20.3 7.0 6.4 Actuarial (Gain) Loss 4.7 (19.5 ) (1.0 ) 8.7 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Participant Contributions — — 4.7 4.3 Medicare Subsidy — — 0.1 (0.1 ) Benefit Obligation as of December 31, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Actual Gain (Loss) on Plan Assets 30.9 2.2 2.5 (2.6 ) Company Contributions 7.2 7.7 — — Participant Contributions — — 4.7 4.3 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Fair Value of Plan Assets as of December 31, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Funded (Underfunded) Status as of December 31, $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Service Cost 6.2 6.4 0.6 0.7 Interest Cost 11.2 10.9 3.3 3.0 Actuarial (Gain) Loss 3.1 (17.9 ) 1.0 2.4 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Participant Contributions — — 2.2 1.9 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Actual Gain (Loss) on Plan Assets 17.3 0.1 3.1 (2.5 ) Company Contributions 5.8 5.9 — — Participant Contributions — — 2.2 1.9 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Fair Value of Plan Assets as of December 31, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Funded (Underfunded) Status as of December 31, $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Service Cost 8.1 8.3 0.8 0.8 Interest Cost 12.4 11.8 3.6 3.4 Actuarial (Gain) Loss 13.8 (16.2 ) 1.5 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Participant Contributions — — 2.4 2.1 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Actual Gain (Loss) on Plan Assets 18.8 1.6 4.1 (3.3 ) Company Contributions 8.4 8.1 — — Participant Contributions — — 2.4 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Funded (Underfunded) Status as of December 31, $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Recognized on the Balance Sheets Pension Plans Other Postretirement Benefit Plans December 31, AEP 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 154.5 $ 185.8 Other Current Liabilities – Accrued Short-term Benefit Liability (5.9 ) (6.3 ) (3.0 ) (3.3 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (252.6 ) (219.0 ) (53.0 ) (55.7 ) Funded (Underfunded) Status $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.2 $ 30.8 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.4 ) (2.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (47.6 ) (50.2 ) (31.5 ) (33.7 ) Underfunded Status $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) Pension Plans Other Postretirement Benefit Plans December 31, I&M 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 19.0 $ 22.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (25.5 ) (21.5 ) — — Funded (Underfunded) Status $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 18.6 $ 23.0 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.1 ) (25.4 ) — — Funded (Underfunded) Status $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2016 2015 2016 2015 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 1.6 $ — $ 8.8 $ 10.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (3.1 ) — — Funded (Underfunded) Status $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 9.9 $ 11.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.2 ) (2.1 ) — — Funded (Underfunded) Status $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Included in AOCI and Regulatory Assets AEP Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 1,569.8 $ 1,546.1 $ 614.4 $ 577.4 Prior Service Cost (Credit) 1.0 3.3 (485.4 ) (554.4 ) Recorded as Regulatory Assets $ 1,415.6 $ 1,385.2 $ 90.4 $ 15.1 Deferred Income Taxes 54.4 57.5 13.5 2.8 Net of Tax AOCI 100.8 106.7 25.1 5.1 APCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 216.2 $ 220.8 $ 92.9 $ 86.9 Prior Service Cost (Credit) 0.2 0.3 (70.5 ) (80.6 ) Recorded as Regulatory Assets $ 213.7 $ 218.3 $ 7.7 $ (0.7 ) Deferred Income Taxes 1.0 1.0 5.1 2.4 Net of Tax AOCI 1.7 1.8 9.6 4.6 I&M Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 133.2 $ 130.0 $ 81.3 $ 77.1 Prior Service Cost (Credit) 0.2 0.3 (66.3 ) (75.7 ) Recorded as Regulatory Assets $ 128.2 $ 125.3 $ 13.7 $ 1.1 Deferred Income Taxes 1.8 1.8 0.5 0.1 Net of Tax AOCI 3.4 3.2 0.8 0.2 OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 215.4 $ 222.0 $ 58.2 $ 52.6 Prior Service Cost (Credit) 0.1 0.2 (48.5 ) (55.4 ) Recorded as Regulatory Assets $ 215.5 $ 222.2 $ 9.7 $ (2.8 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 91.0 $ 94.1 $ 37.3 $ 35.2 Prior Service Cost (Credit) — 0.3 (30.2 ) (34.5 ) Recorded as Regulatory Assets $ 91.0 $ 94.4 $ 7.1 $ 0.7 SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 103.8 $ 97.1 $ 45.4 $ 43.3 Prior Service Cost (Credit) 0.1 0.4 (36.6 ) (41.6 ) Recorded as Regulatory Assets $ 103.9 $ 97.5 $ 5.7 $ 1.2 Deferred Income Taxes — — 1.1 0.2 Net of Tax AOCI — — 2.0 0.3 Components of the change in amounts included in AOCI and Regulatory Assets by Registrant are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 107.5 $ 41.8 $ 68.4 $ 176.3 Amortization of Actuarial Loss (83.8 ) (107.1 ) (31.4 ) (18.8 ) Amortization of Prior Service Credit (Cost) (2.3 ) (2.2 ) 69.0 69.1 Change for the Year Ended December 31, $ 21.4 $ (67.5 ) $ 106.0 $ 226.6 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.2 $ (0.3 ) $ 11.4 $ 24.7 Amortization of Actuarial Loss (10.8 ) (13.9 ) (5.4 ) (3.6 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 10.1 10.0 Change for the Year Ended December 31, $ (4.7 ) $ (14.4 ) $ 16.1 $ 31.1 I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 13.2 $ 4.7 $ 7.9 $ 24.7 Amortization of Actuarial Loss (10.0 ) (12.6 ) (3.7 ) (2.0 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ 3.1 $ (8.1 ) $ 13.6 $ 32.1 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 1.5 $ 5.8 $ 9.4 $ 24.0 Amortization of Actuarial Loss (8.1 ) (10.5 ) (3.8 ) (2.1 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 6.9 7.0 Change for the Year Ended December 31, $ (6.7 ) $ (4.9 ) $ 12.5 $ 28.9 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.3 $ (2.9 ) $ 3.9 $ 10.9 Amortization of Actuarial Loss (4.4 ) (5.7 ) (1.8 ) (1.0 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.2 ) 4.3 4.3 Change for the Year Ended December 31, $ (3.4 ) $ (8.8 ) $ 6.4 $ 14.2 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.5 $ (1.8 ) $ 4.0 $ 12.0 Amortization of Actuarial Loss (4.8 ) (6.0 ) (1.9 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.0 5.2 Change for the Year Ended December 31, $ 6.4 $ (8.1 ) $ 7.1 $ 16.1 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below: Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 354.7 $ — $ — $ — $ 354.7 7.3 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Real Estate Investment Trusts 3.1 — — — 3.1 0.1 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trusts (c) — 16.1 — 369.7 385.8 8.1 % Subtotal – Equities 722.0 31.7 — 369.7 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 34.2 34.2 0.7 % United States Government and Agency Securities (c) — 397.8 — 24.1 421.9 8.9 % Corporate Debt (c) — 1,964.2 — 19.0 1,983.2 41.6 % Foreign Debt (c) — 405.4 0.1 16.0 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed (c) — 15.8 — 7.6 23.4 0.5 % Subtotal – Fixed Income — 2,796.0 0.1 100.9 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents (c) — 1.2 — 47.4 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,091.9 $ 674.5 $ 279.2 $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trusts (b) — 12.6 — 19.0 31.6 2.0 % Subtotal – Equities 949.4 28.2 — 19.0 996.6 63.2 % Fixed Income: Common Collective Trust – Debt (b) — — — 100.9 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 209.4 — 100.9 310.3 19.6 % Trust Owned Life Insurance: International Equities (b) — — — 28.3 28.3 1.8 % United States Bonds (b) — — — 184.3 184.3 11.7 % Subtotal – Trust Owned Life Insurance — — — 212.6 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 244.8 $ — $ 338.3 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2017 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 85.8 $ 93.5 $ 71.9 $ 10.2 $ 12.2 $ 14.2 Interest Cost 211.6 205.3 221.0 60.9 56.8 67.2 Expected Return on Plan Assets (280.3 ) (274.8 ) (261.6 ) (107.0 ) (111.0 ) (111.3 ) Amortization of Prior Service
Ohio Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2016 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions used for OPEB plans measurement purposes are shown below: January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2016 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Service Cost 85.8 93.5 10.2 12.2 Interest Cost 211.6 205.3 60.9 56.8 Actuarial (Gain) Loss 142.7 (200.6 ) 17.3 37.2 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Participant Contributions — — 37.8 33.3 Medicare Subsidy — — 0.8 0.8 Benefit Obligation as of December 31, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Actual Gain (Loss) on Plan Assets 315.5 32.4 56.0 (34.0 ) Company Contributions 91.4 97.9 4.9 12.9 Participant Contributions — — 37.8 33.3 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Fair Value of Plan Assets as of December 31, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Funded (Underfunded) Status as of December 31, $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Service Cost 8.1 8.7 1.0 1.1 Interest Cost 27.2 26.7 10.8 10.3 Actuarial (Gain) Loss 9.2 (41.4 ) (0.2 ) 2.5 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Participant Contributions — — 6.4 5.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Actual Gain (Loss) on Plan Assets 38.3 (5.7 ) 5.9 (7.7 ) Company Contributions 8.8 10.0 2.7 2.8 Participant Contributions — — 6.4 5.7 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Fair Value of Plan Assets as of December 31, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Underfunded Status as of December 31, $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Service Cost 12.2 12.9 1.5 1.6 Interest Cost 25.3 24.5 7.0 6.4 Actuarial (Gain) Loss 20.1 (28.4 ) 3.8 7.7 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Participant Contributions — — 4.6 4.0 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Actual Gain (Loss) on Plan Assets 40.6 (0.9 ) 8.7 (2.3 ) Company Contributions 13.0 14.6 — 0.1 Participant Contributions — — 4.6 4.0 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Fair Value of Plan Assets as of December 31, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Funded (Underfunded) Status as of December 31, $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Service Cost 6.5 6.7 0.8 0.9 Interest Cost 20.6 20.3 7.0 6.4 Actuarial (Gain) Loss 4.7 (19.5 ) (1.0 ) 8.7 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Participant Contributions — — 4.7 4.3 Medicare Subsidy — — 0.1 (0.1 ) Benefit Obligation as of December 31, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Actual Gain (Loss) on Plan Assets 30.9 2.2 2.5 (2.6 ) Company Contributions 7.2 7.7 — — Participant Contributions — — 4.7 4.3 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Fair Value of Plan Assets as of December 31, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Funded (Underfunded) Status as of December 31, $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Service Cost 6.2 6.4 0.6 0.7 Interest Cost 11.2 10.9 3.3 3.0 Actuarial (Gain) Loss 3.1 (17.9 ) 1.0 2.4 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Participant Contributions — — 2.2 1.9 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Actual Gain (Loss) on Plan Assets 17.3 0.1 3.1 (2.5 ) Company Contributions 5.8 5.9 — — Participant Contributions — — 2.2 1.9 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Fair Value of Plan Assets as of December 31, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Funded (Underfunded) Status as of December 31, $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Service Cost 8.1 8.3 0.8 0.8 Interest Cost 12.4 11.8 3.6 3.4 Actuarial (Gain) Loss 13.8 (16.2 ) 1.5 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Participant Contributions — — 2.4 2.1 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Actual Gain (Loss) on Plan Assets 18.8 1.6 4.1 (3.3 ) Company Contributions 8.4 8.1 — — Participant Contributions — — 2.4 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Funded (Underfunded) Status as of December 31, $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Recognized on the Balance Sheets Pension Plans Other Postretirement Benefit Plans December 31, AEP 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 154.5 $ 185.8 Other Current Liabilities – Accrued Short-term Benefit Liability (5.9 ) (6.3 ) (3.0 ) (3.3 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (252.6 ) (219.0 ) (53.0 ) (55.7 ) Funded (Underfunded) Status $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.2 $ 30.8 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.4 ) (2.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (47.6 ) (50.2 ) (31.5 ) (33.7 ) Underfunded Status $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) Pension Plans Other Postretirement Benefit Plans December 31, I&M 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 19.0 $ 22.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (25.5 ) (21.5 ) — — Funded (Underfunded) Status $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 18.6 $ 23.0 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.1 ) (25.4 ) — — Funded (Underfunded) Status $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2016 2015 2016 2015 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 1.6 $ — $ 8.8 $ 10.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (3.1 ) — — Funded (Underfunded) Status $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 9.9 $ 11.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.2 ) (2.1 ) — — Funded (Underfunded) Status $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Included in AOCI and Regulatory Assets AEP Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 1,569.8 $ 1,546.1 $ 614.4 $ 577.4 Prior Service Cost (Credit) 1.0 3.3 (485.4 ) (554.4 ) Recorded as Regulatory Assets $ 1,415.6 $ 1,385.2 $ 90.4 $ 15.1 Deferred Income Taxes 54.4 57.5 13.5 2.8 Net of Tax AOCI 100.8 106.7 25.1 5.1 APCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 216.2 $ 220.8 $ 92.9 $ 86.9 Prior Service Cost (Credit) 0.2 0.3 (70.5 ) (80.6 ) Recorded as Regulatory Assets $ 213.7 $ 218.3 $ 7.7 $ (0.7 ) Deferred Income Taxes 1.0 1.0 5.1 2.4 Net of Tax AOCI 1.7 1.8 9.6 4.6 I&M Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 133.2 $ 130.0 $ 81.3 $ 77.1 Prior Service Cost (Credit) 0.2 0.3 (66.3 ) (75.7 ) Recorded as Regulatory Assets $ 128.2 $ 125.3 $ 13.7 $ 1.1 Deferred Income Taxes 1.8 1.8 0.5 0.1 Net of Tax AOCI 3.4 3.2 0.8 0.2 OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 215.4 $ 222.0 $ 58.2 $ 52.6 Prior Service Cost (Credit) 0.1 0.2 (48.5 ) (55.4 ) Recorded as Regulatory Assets $ 215.5 $ 222.2 $ 9.7 $ (2.8 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 91.0 $ 94.1 $ 37.3 $ 35.2 Prior Service Cost (Credit) — 0.3 (30.2 ) (34.5 ) Recorded as Regulatory Assets $ 91.0 $ 94.4 $ 7.1 $ 0.7 SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 103.8 $ 97.1 $ 45.4 $ 43.3 Prior Service Cost (Credit) 0.1 0.4 (36.6 ) (41.6 ) Recorded as Regulatory Assets $ 103.9 $ 97.5 $ 5.7 $ 1.2 Deferred Income Taxes — — 1.1 0.2 Net of Tax AOCI — — 2.0 0.3 Components of the change in amounts included in AOCI and Regulatory Assets by Registrant are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 107.5 $ 41.8 $ 68.4 $ 176.3 Amortization of Actuarial Loss (83.8 ) (107.1 ) (31.4 ) (18.8 ) Amortization of Prior Service Credit (Cost) (2.3 ) (2.2 ) 69.0 69.1 Change for the Year Ended December 31, $ 21.4 $ (67.5 ) $ 106.0 $ 226.6 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.2 $ (0.3 ) $ 11.4 $ 24.7 Amortization of Actuarial Loss (10.8 ) (13.9 ) (5.4 ) (3.6 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 10.1 10.0 Change for the Year Ended December 31, $ (4.7 ) $ (14.4 ) $ 16.1 $ 31.1 I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 13.2 $ 4.7 $ 7.9 $ 24.7 Amortization of Actuarial Loss (10.0 ) (12.6 ) (3.7 ) (2.0 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ 3.1 $ (8.1 ) $ 13.6 $ 32.1 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 1.5 $ 5.8 $ 9.4 $ 24.0 Amortization of Actuarial Loss (8.1 ) (10.5 ) (3.8 ) (2.1 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 6.9 7.0 Change for the Year Ended December 31, $ (6.7 ) $ (4.9 ) $ 12.5 $ 28.9 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.3 $ (2.9 ) $ 3.9 $ 10.9 Amortization of Actuarial Loss (4.4 ) (5.7 ) (1.8 ) (1.0 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.2 ) 4.3 4.3 Change for the Year Ended December 31, $ (3.4 ) $ (8.8 ) $ 6.4 $ 14.2 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.5 $ (1.8 ) $ 4.0 $ 12.0 Amortization of Actuarial Loss (4.8 ) (6.0 ) (1.9 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.0 5.2 Change for the Year Ended December 31, $ 6.4 $ (8.1 ) $ 7.1 $ 16.1 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below: Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 354.7 $ — $ — $ — $ 354.7 7.3 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Real Estate Investment Trusts 3.1 — — — 3.1 0.1 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trusts (c) — 16.1 — 369.7 385.8 8.1 % Subtotal – Equities 722.0 31.7 — 369.7 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 34.2 34.2 0.7 % United States Government and Agency Securities (c) — 397.8 — 24.1 421.9 8.9 % Corporate Debt (c) — 1,964.2 — 19.0 1,983.2 41.6 % Foreign Debt (c) — 405.4 0.1 16.0 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed (c) — 15.8 — 7.6 23.4 0.5 % Subtotal – Fixed Income — 2,796.0 0.1 100.9 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents (c) — 1.2 — 47.4 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,091.9 $ 674.5 $ 279.2 $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trusts (b) — 12.6 — 19.0 31.6 2.0 % Subtotal – Equities 949.4 28.2 — 19.0 996.6 63.2 % Fixed Income: Common Collective Trust – Debt (b) — — — 100.9 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 209.4 — 100.9 310.3 19.6 % Trust Owned Life Insurance: International Equities (b) — — — 28.3 28.3 1.8 % United States Bonds (b) — — — 184.3 184.3 11.7 % Subtotal – Trust Owned Life Insurance — — — 212.6 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 244.8 $ — $ 338.3 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2017 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 85.8 $ 93.5 $ 71.9 $ 10.2 $ 12.2 $ 14.2 Interest Cost 211.6 205.3 221.0 60.9 56.8 67.2 Expected Return on Plan Assets (280.3 ) (274.8 ) (261.6 ) (107.0 ) (111.0 ) (111.3 ) Amortization of Prior Service
Public Service Co Of Oklahoma [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2016 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions used for OPEB plans measurement purposes are shown below: January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2016 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Service Cost 85.8 93.5 10.2 12.2 Interest Cost 211.6 205.3 60.9 56.8 Actuarial (Gain) Loss 142.7 (200.6 ) 17.3 37.2 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Participant Contributions — — 37.8 33.3 Medicare Subsidy — — 0.8 0.8 Benefit Obligation as of December 31, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Actual Gain (Loss) on Plan Assets 315.5 32.4 56.0 (34.0 ) Company Contributions 91.4 97.9 4.9 12.9 Participant Contributions — — 37.8 33.3 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Fair Value of Plan Assets as of December 31, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Funded (Underfunded) Status as of December 31, $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Service Cost 8.1 8.7 1.0 1.1 Interest Cost 27.2 26.7 10.8 10.3 Actuarial (Gain) Loss 9.2 (41.4 ) (0.2 ) 2.5 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Participant Contributions — — 6.4 5.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Actual Gain (Loss) on Plan Assets 38.3 (5.7 ) 5.9 (7.7 ) Company Contributions 8.8 10.0 2.7 2.8 Participant Contributions — — 6.4 5.7 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Fair Value of Plan Assets as of December 31, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Underfunded Status as of December 31, $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Service Cost 12.2 12.9 1.5 1.6 Interest Cost 25.3 24.5 7.0 6.4 Actuarial (Gain) Loss 20.1 (28.4 ) 3.8 7.7 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Participant Contributions — — 4.6 4.0 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Actual Gain (Loss) on Plan Assets 40.6 (0.9 ) 8.7 (2.3 ) Company Contributions 13.0 14.6 — 0.1 Participant Contributions — — 4.6 4.0 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Fair Value of Plan Assets as of December 31, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Funded (Underfunded) Status as of December 31, $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Service Cost 6.5 6.7 0.8 0.9 Interest Cost 20.6 20.3 7.0 6.4 Actuarial (Gain) Loss 4.7 (19.5 ) (1.0 ) 8.7 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Participant Contributions — — 4.7 4.3 Medicare Subsidy — — 0.1 (0.1 ) Benefit Obligation as of December 31, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Actual Gain (Loss) on Plan Assets 30.9 2.2 2.5 (2.6 ) Company Contributions 7.2 7.7 — — Participant Contributions — — 4.7 4.3 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Fair Value of Plan Assets as of December 31, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Funded (Underfunded) Status as of December 31, $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Service Cost 6.2 6.4 0.6 0.7 Interest Cost 11.2 10.9 3.3 3.0 Actuarial (Gain) Loss 3.1 (17.9 ) 1.0 2.4 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Participant Contributions — — 2.2 1.9 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Actual Gain (Loss) on Plan Assets 17.3 0.1 3.1 (2.5 ) Company Contributions 5.8 5.9 — — Participant Contributions — — 2.2 1.9 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Fair Value of Plan Assets as of December 31, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Funded (Underfunded) Status as of December 31, $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Service Cost 8.1 8.3 0.8 0.8 Interest Cost 12.4 11.8 3.6 3.4 Actuarial (Gain) Loss 13.8 (16.2 ) 1.5 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Participant Contributions — — 2.4 2.1 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Actual Gain (Loss) on Plan Assets 18.8 1.6 4.1 (3.3 ) Company Contributions 8.4 8.1 — — Participant Contributions — — 2.4 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Funded (Underfunded) Status as of December 31, $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Recognized on the Balance Sheets Pension Plans Other Postretirement Benefit Plans December 31, AEP 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 154.5 $ 185.8 Other Current Liabilities – Accrued Short-term Benefit Liability (5.9 ) (6.3 ) (3.0 ) (3.3 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (252.6 ) (219.0 ) (53.0 ) (55.7 ) Funded (Underfunded) Status $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.2 $ 30.8 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.4 ) (2.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (47.6 ) (50.2 ) (31.5 ) (33.7 ) Underfunded Status $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) Pension Plans Other Postretirement Benefit Plans December 31, I&M 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 19.0 $ 22.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (25.5 ) (21.5 ) — — Funded (Underfunded) Status $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 18.6 $ 23.0 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.1 ) (25.4 ) — — Funded (Underfunded) Status $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2016 2015 2016 2015 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 1.6 $ — $ 8.8 $ 10.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (3.1 ) — — Funded (Underfunded) Status $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 9.9 $ 11.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.2 ) (2.1 ) — — Funded (Underfunded) Status $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Included in AOCI and Regulatory Assets AEP Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 1,569.8 $ 1,546.1 $ 614.4 $ 577.4 Prior Service Cost (Credit) 1.0 3.3 (485.4 ) (554.4 ) Recorded as Regulatory Assets $ 1,415.6 $ 1,385.2 $ 90.4 $ 15.1 Deferred Income Taxes 54.4 57.5 13.5 2.8 Net of Tax AOCI 100.8 106.7 25.1 5.1 APCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 216.2 $ 220.8 $ 92.9 $ 86.9 Prior Service Cost (Credit) 0.2 0.3 (70.5 ) (80.6 ) Recorded as Regulatory Assets $ 213.7 $ 218.3 $ 7.7 $ (0.7 ) Deferred Income Taxes 1.0 1.0 5.1 2.4 Net of Tax AOCI 1.7 1.8 9.6 4.6 I&M Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 133.2 $ 130.0 $ 81.3 $ 77.1 Prior Service Cost (Credit) 0.2 0.3 (66.3 ) (75.7 ) Recorded as Regulatory Assets $ 128.2 $ 125.3 $ 13.7 $ 1.1 Deferred Income Taxes 1.8 1.8 0.5 0.1 Net of Tax AOCI 3.4 3.2 0.8 0.2 OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 215.4 $ 222.0 $ 58.2 $ 52.6 Prior Service Cost (Credit) 0.1 0.2 (48.5 ) (55.4 ) Recorded as Regulatory Assets $ 215.5 $ 222.2 $ 9.7 $ (2.8 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 91.0 $ 94.1 $ 37.3 $ 35.2 Prior Service Cost (Credit) — 0.3 (30.2 ) (34.5 ) Recorded as Regulatory Assets $ 91.0 $ 94.4 $ 7.1 $ 0.7 SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 103.8 $ 97.1 $ 45.4 $ 43.3 Prior Service Cost (Credit) 0.1 0.4 (36.6 ) (41.6 ) Recorded as Regulatory Assets $ 103.9 $ 97.5 $ 5.7 $ 1.2 Deferred Income Taxes — — 1.1 0.2 Net of Tax AOCI — — 2.0 0.3 Components of the change in amounts included in AOCI and Regulatory Assets by Registrant are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 107.5 $ 41.8 $ 68.4 $ 176.3 Amortization of Actuarial Loss (83.8 ) (107.1 ) (31.4 ) (18.8 ) Amortization of Prior Service Credit (Cost) (2.3 ) (2.2 ) 69.0 69.1 Change for the Year Ended December 31, $ 21.4 $ (67.5 ) $ 106.0 $ 226.6 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.2 $ (0.3 ) $ 11.4 $ 24.7 Amortization of Actuarial Loss (10.8 ) (13.9 ) (5.4 ) (3.6 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 10.1 10.0 Change for the Year Ended December 31, $ (4.7 ) $ (14.4 ) $ 16.1 $ 31.1 I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 13.2 $ 4.7 $ 7.9 $ 24.7 Amortization of Actuarial Loss (10.0 ) (12.6 ) (3.7 ) (2.0 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ 3.1 $ (8.1 ) $ 13.6 $ 32.1 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 1.5 $ 5.8 $ 9.4 $ 24.0 Amortization of Actuarial Loss (8.1 ) (10.5 ) (3.8 ) (2.1 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 6.9 7.0 Change for the Year Ended December 31, $ (6.7 ) $ (4.9 ) $ 12.5 $ 28.9 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.3 $ (2.9 ) $ 3.9 $ 10.9 Amortization of Actuarial Loss (4.4 ) (5.7 ) (1.8 ) (1.0 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.2 ) 4.3 4.3 Change for the Year Ended December 31, $ (3.4 ) $ (8.8 ) $ 6.4 $ 14.2 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.5 $ (1.8 ) $ 4.0 $ 12.0 Amortization of Actuarial Loss (4.8 ) (6.0 ) (1.9 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.0 5.2 Change for the Year Ended December 31, $ 6.4 $ (8.1 ) $ 7.1 $ 16.1 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below: Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 354.7 $ — $ — $ — $ 354.7 7.3 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Real Estate Investment Trusts 3.1 — — — 3.1 0.1 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trusts (c) — 16.1 — 369.7 385.8 8.1 % Subtotal – Equities 722.0 31.7 — 369.7 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 34.2 34.2 0.7 % United States Government and Agency Securities (c) — 397.8 — 24.1 421.9 8.9 % Corporate Debt (c) — 1,964.2 — 19.0 1,983.2 41.6 % Foreign Debt (c) — 405.4 0.1 16.0 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed (c) — 15.8 — 7.6 23.4 0.5 % Subtotal – Fixed Income — 2,796.0 0.1 100.9 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents (c) — 1.2 — 47.4 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,091.9 $ 674.5 $ 279.2 $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trusts (b) — 12.6 — 19.0 31.6 2.0 % Subtotal – Equities 949.4 28.2 — 19.0 996.6 63.2 % Fixed Income: Common Collective Trust – Debt (b) — — — 100.9 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 209.4 — 100.9 310.3 19.6 % Trust Owned Life Insurance: International Equities (b) — — — 28.3 28.3 1.8 % United States Bonds (b) — — — 184.3 184.3 11.7 % Subtotal – Trust Owned Life Insurance — — — 212.6 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 244.8 $ — $ 338.3 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2017 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 85.8 $ 93.5 $ 71.9 $ 10.2 $ 12.2 $ 14.2 Interest Cost 211.6 205.3 221.0 60.9 56.8 67.2 Expected Return on Plan Assets (280.3 ) (274.8 ) (261.6 ) (107.0 ) (111.0 ) (111.3 ) Amortization of Prior Service
Southwestern Electric Power Co [Member]
Benefit Plans	BENEFIT PLANS The disclosures in this note apply to all Registrants unless indicated otherwise. For a discussion of investment strategy, investment limitations, target asset allocations and the classification of investments within the fair value hierarchy, see “Fair Value Measurements of Assets and Liabilities” and “Investments Held in Trust for Future Liabilities” sections of Note 1 . AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability. Actuarial Assumptions for Benefit Obligations The weighted-average assumptions used in the measurement of the Registrants’ benefit obligations are shown in the following tables: Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. A duration-based method is used to determine the discount rate for the plans. A hypothetical portfolio of high quality corporate bonds is constructed with cash flows matching the benefit plan liability. The composite yield on the hypothetical bond portfolio is used as the discount rate for the plan. The discount rate is the same for each Registrant. For 2016 , the rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 12% per year, with the average increase shown in the table above. The compensation increase rates reflect variations in each Registrants’ population participating in the pension plan. Actuarial Assumptions for Net Periodic Benefit Costs The weighted-average assumptions used in the measurement of each Registrants’ benefit costs are shown in the following tables: Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees. The expected return on plan assets was determined by evaluating historical returns, the current investment climate (yield on fixed income securities and other recent investment market indicators), rate of inflation, third party forecasts and current prospects for economic growth. The expected return on plan assets is the same for each Registrant. The health care trend rate assumptions used for OPEB plans measurement purposes are shown below: January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020 Assumed health care cost trend rates have a significant effect on the amounts reported for the OPEB health care plans. A 1% change in assumed health care cost trend rates would have the following effects: AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 ) Significant Concentrations of Risk within Plan Assets In addition to establishing the target asset allocation of plan assets, the investment policy also places restrictions on securities to limit significant concentrations within plan assets. The investment policy establishes guidelines that govern maximum market exposure, security restrictions, prohibited asset classes, prohibited types of transactions, minimum credit quality, average portfolio credit quality, portfolio duration and concentration limits. The guidelines were established to mitigate the risk of loss due to significant concentrations in any investment. Management monitors the plans to control security diversification and ensure compliance with the investment policy. As of December 31, 2016 , the assets were invested in compliance with all investment limits. See “Investments Held in Trust for Future Liabilities” section of Note 1 for limit details. Benefit Plan Obligations, Plan Assets and Funded Status The following tables provide a reconciliation of the changes in the plans’ benefit obligations, fair value of plan assets and funded status. The benefit obligation for the defined benefit pension and OPEB plans are the projected benefit obligation and the accumulated benefit obligation, respectively. AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Service Cost 85.8 93.5 10.2 12.2 Interest Cost 211.6 205.3 60.9 56.8 Actuarial (Gain) Loss 142.7 (200.6 ) 17.3 37.2 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Participant Contributions — — 37.8 33.3 Medicare Subsidy — — 0.8 0.8 Benefit Obligation as of December 31, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Actual Gain (Loss) on Plan Assets 315.5 32.4 56.0 (34.0 ) Company Contributions 91.4 97.9 4.9 12.9 Participant Contributions — — 37.8 33.3 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Fair Value of Plan Assets as of December 31, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Funded (Underfunded) Status as of December 31, $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Service Cost 8.1 8.7 1.0 1.1 Interest Cost 27.2 26.7 10.8 10.3 Actuarial (Gain) Loss 9.2 (41.4 ) (0.2 ) 2.5 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Participant Contributions — — 6.4 5.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Actual Gain (Loss) on Plan Assets 38.3 (5.7 ) 5.9 (7.7 ) Company Contributions 8.8 10.0 2.7 2.8 Participant Contributions — — 6.4 5.7 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Fair Value of Plan Assets as of December 31, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Underfunded Status as of December 31, $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Service Cost 12.2 12.9 1.5 1.6 Interest Cost 25.3 24.5 7.0 6.4 Actuarial (Gain) Loss 20.1 (28.4 ) 3.8 7.7 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Participant Contributions — — 4.6 4.0 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Actual Gain (Loss) on Plan Assets 40.6 (0.9 ) 8.7 (2.3 ) Company Contributions 13.0 14.6 — 0.1 Participant Contributions — — 4.6 4.0 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Fair Value of Plan Assets as of December 31, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Funded (Underfunded) Status as of December 31, $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Service Cost 6.5 6.7 0.8 0.9 Interest Cost 20.6 20.3 7.0 6.4 Actuarial (Gain) Loss 4.7 (19.5 ) (1.0 ) 8.7 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Participant Contributions — — 4.7 4.3 Medicare Subsidy — — 0.1 (0.1 ) Benefit Obligation as of December 31, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Actual Gain (Loss) on Plan Assets 30.9 2.2 2.5 (2.6 ) Company Contributions 7.2 7.7 — — Participant Contributions — — 4.7 4.3 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Fair Value of Plan Assets as of December 31, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Funded (Underfunded) Status as of December 31, $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Service Cost 6.2 6.4 0.6 0.7 Interest Cost 11.2 10.9 3.3 3.0 Actuarial (Gain) Loss 3.1 (17.9 ) 1.0 2.4 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Participant Contributions — — 2.2 1.9 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Actual Gain (Loss) on Plan Assets 17.3 0.1 3.1 (2.5 ) Company Contributions 5.8 5.9 — — Participant Contributions — — 2.2 1.9 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Fair Value of Plan Assets as of December 31, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Funded (Underfunded) Status as of December 31, $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Service Cost 8.1 8.3 0.8 0.8 Interest Cost 12.4 11.8 3.6 3.4 Actuarial (Gain) Loss 13.8 (16.2 ) 1.5 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Participant Contributions — — 2.4 2.1 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Actual Gain (Loss) on Plan Assets 18.8 1.6 4.1 (3.3 ) Company Contributions 8.4 8.1 — — Participant Contributions — — 2.4 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Funded (Underfunded) Status as of December 31, $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Recognized on the Balance Sheets Pension Plans Other Postretirement Benefit Plans December 31, AEP 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 154.5 $ 185.8 Other Current Liabilities – Accrued Short-term Benefit Liability (5.9 ) (6.3 ) (3.0 ) (3.3 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (252.6 ) (219.0 ) (53.0 ) (55.7 ) Funded (Underfunded) Status $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8 Pension Plans Other Postretirement Benefit Plans December 31, APCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.2 $ 30.8 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.4 ) (2.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (47.6 ) (50.2 ) (31.5 ) (33.7 ) Underfunded Status $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 ) Pension Plans Other Postretirement Benefit Plans December 31, I&M 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 19.0 $ 22.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (25.5 ) (21.5 ) — — Funded (Underfunded) Status $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7 Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 18.6 $ 23.0 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.1 ) (25.4 ) — — Funded (Underfunded) Status $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0 Pension Plans Other Postretirement Benefit Plans December 31, PSO 2016 2015 2016 2015 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 1.6 $ — $ 8.8 $ 10.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (3.1 ) — — Funded (Underfunded) Status $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6 Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 9.9 $ 11.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.2 ) (2.1 ) — — Funded (Underfunded) Status $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7 Amounts Included in AOCI and Regulatory Assets AEP Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 1,569.8 $ 1,546.1 $ 614.4 $ 577.4 Prior Service Cost (Credit) 1.0 3.3 (485.4 ) (554.4 ) Recorded as Regulatory Assets $ 1,415.6 $ 1,385.2 $ 90.4 $ 15.1 Deferred Income Taxes 54.4 57.5 13.5 2.8 Net of Tax AOCI 100.8 106.7 25.1 5.1 APCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 216.2 $ 220.8 $ 92.9 $ 86.9 Prior Service Cost (Credit) 0.2 0.3 (70.5 ) (80.6 ) Recorded as Regulatory Assets $ 213.7 $ 218.3 $ 7.7 $ (0.7 ) Deferred Income Taxes 1.0 1.0 5.1 2.4 Net of Tax AOCI 1.7 1.8 9.6 4.6 I&M Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 133.2 $ 130.0 $ 81.3 $ 77.1 Prior Service Cost (Credit) 0.2 0.3 (66.3 ) (75.7 ) Recorded as Regulatory Assets $ 128.2 $ 125.3 $ 13.7 $ 1.1 Deferred Income Taxes 1.8 1.8 0.5 0.1 Net of Tax AOCI 3.4 3.2 0.8 0.2 OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 215.4 $ 222.0 $ 58.2 $ 52.6 Prior Service Cost (Credit) 0.1 0.2 (48.5 ) (55.4 ) Recorded as Regulatory Assets $ 215.5 $ 222.2 $ 9.7 $ (2.8 ) PSO Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 91.0 $ 94.1 $ 37.3 $ 35.2 Prior Service Cost (Credit) — 0.3 (30.2 ) (34.5 ) Recorded as Regulatory Assets $ 91.0 $ 94.4 $ 7.1 $ 0.7 SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 103.8 $ 97.1 $ 45.4 $ 43.3 Prior Service Cost (Credit) 0.1 0.4 (36.6 ) (41.6 ) Recorded as Regulatory Assets $ 103.9 $ 97.5 $ 5.7 $ 1.2 Deferred Income Taxes — — 1.1 0.2 Net of Tax AOCI — — 2.0 0.3 Components of the change in amounts included in AOCI and Regulatory Assets by Registrant are as follows: AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 107.5 $ 41.8 $ 68.4 $ 176.3 Amortization of Actuarial Loss (83.8 ) (107.1 ) (31.4 ) (18.8 ) Amortization of Prior Service Credit (Cost) (2.3 ) (2.2 ) 69.0 69.1 Change for the Year Ended December 31, $ 21.4 $ (67.5 ) $ 106.0 $ 226.6 APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.2 $ (0.3 ) $ 11.4 $ 24.7 Amortization of Actuarial Loss (10.8 ) (13.9 ) (5.4 ) (3.6 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 10.1 10.0 Change for the Year Ended December 31, $ (4.7 ) $ (14.4 ) $ 16.1 $ 31.1 I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 13.2 $ 4.7 $ 7.9 $ 24.7 Amortization of Actuarial Loss (10.0 ) (12.6 ) (3.7 ) (2.0 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ 3.1 $ (8.1 ) $ 13.6 $ 32.1 OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 1.5 $ 5.8 $ 9.4 $ 24.0 Amortization of Actuarial Loss (8.1 ) (10.5 ) (3.8 ) (2.1 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 6.9 7.0 Change for the Year Ended December 31, $ (6.7 ) $ (4.9 ) $ 12.5 $ 28.9 PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.3 $ (2.9 ) $ 3.9 $ 10.9 Amortization of Actuarial Loss (4.4 ) (5.7 ) (1.8 ) (1.0 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.2 ) 4.3 4.3 Change for the Year Ended December 31, $ (3.4 ) $ (8.8 ) $ 6.4 $ 14.2 SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.5 $ (1.8 ) $ 4.0 $ 12.0 Amortization of Actuarial Loss (4.8 ) (6.0 ) (1.9 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.0 5.2 Change for the Year Ended December 31, $ 6.4 $ (8.1 ) $ 7.1 $ 16.1 Pension and Other Postretirement Benefits Plans’ Assets The fair value tables within Pension and Other Postretirement Benefits Plans’ Assets present the classification of assets for AEP within the fair value hierarchy. All Level 1, 2, 3 and Other amounts can be allocated to the Registrant Subsidiaries using the percentages in the table below: Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 % The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 354.7 $ — $ — $ — $ 354.7 7.3 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Real Estate Investment Trusts 3.1 — — — 3.1 0.1 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2016 : Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table presents the classification of pension plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trusts (c) — 16.1 — 369.7 385.8 8.1 % Subtotal – Equities 722.0 31.7 — 369.7 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 34.2 34.2 0.7 % United States Government and Agency Securities (c) — 397.8 — 24.1 421.9 8.9 % Corporate Debt (c) — 1,964.2 — 19.0 1,983.2 41.6 % Foreign Debt (c) — 405.4 0.1 16.0 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed (c) — 15.8 — 7.6 23.4 0.5 % Subtotal – Fixed Income — 2,796.0 0.1 100.9 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents (c) — 1.2 — 47.4 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,091.9 $ 674.5 $ 279.2 $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. The following table sets forth a reconciliation of changes in the fair value of AEP’s assets classified as Level 3 in the fair value hierarchy for the pension assets: Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 The following table presents the classification of OPEB plan assets for AEP within the fair value hierarchy as of December 31, 2015 : Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trusts (b) — 12.6 — 19.0 31.6 2.0 % Subtotal – Equities 949.4 28.2 — 19.0 996.6 63.2 % Fixed Income: Common Collective Trust – Debt (b) — — — 100.9 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 209.4 — 100.9 310.3 19.6 % Trust Owned Life Insurance: International Equities (b) — — — 28.3 28.3 1.8 % United States Bonds (b) — — — 184.3 184.3 11.7 % Subtotal – Trust Owned Life Insurance — — — 212.6 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 244.8 $ — $ 338.3 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. Determination of Pension Expense The determination of pension expense or income is based on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return. The accumulated benefit obligation for the pension plans is as follows: Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3 For the underfunded pension plans that had an accumulated benefit obligation in excess of plan assets, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets of these plans were as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 ) Estimated Future Benefit Payments and Contributions The estimated pension benefit payments and contributions to the trust are at least the minimum amount required by the Employee Retirement Income Security Act plus payment of unfunded nonqualified benefits. For the qualified pension plan, additional discretionary contributions may also be made to maintain the funded status of the plan. For OPEB plans, expected payments include the payment of unfunded benefits. The following table provides the estimated contributions and payments by Registrant for 2017 : Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 — The tables below reflect the total benefits expected to be paid from the plan or from the Registrants’ assets. The payments include the participants’ contributions to the plan for their share of the cost. Future benefit payments are dependent on the number of employees retiring, whether the retiring employees elect to receive pension benefits as annuities or as lump sum distributions, future integration of the benefit plans with changes to Medicare and other legislation, future levels of interest rates and variances in actuarial results. The estimated payments for the pension benefits and OPEB are as follows: Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — — Components of Net Periodic Benefit Cost The following tables provide the components of net periodic benefit cost (credit) by Registrant for the plans: AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 85.8 $ 93.5 $ 71.9 $ 10.2 $ 12.2 $ 14.2 Interest Cost 211.6 205.3 221.0 60.9 56.8 67.2 Expected Return on Plan Assets (280.3 ) (274.8 ) (261.6 ) (107.0 ) (111.0 ) (111.3 ) Amortization of Prior Service

Business Segments

Business Segments	12 Months Ended
	Dec. 31, 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 and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2016 , 2015 and 2014 and reportable segment balance sheet information as of December 31, 2016 and 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (d) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (d) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (d) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (d) 16,397.3 Total Property, Plant and Equipment – Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (d) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (d) (e) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (d) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 20,242.2 $ (19,573.0 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees $ 31.9 $ 0.9 $ 630.8 $ 0.1 $ 56.8 $ — $ 720.5 Long-term Debt Due Within One Year: Non-Affiliated $ 935.4 $ 824.7 $ — $ 71.6 $ 0.1 $ — $ 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 10.1 — 4.7 8.6 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 280.3 23.5 45.3 25.1 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.7 62.9 179.3 15.2 — 902.6 Income from Continuing Operations $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 8.3 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 55.8 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Assets $ 33,705.1 $ 14,524.6 $ 3,570.0 $ 6,326.2 $ 20,512.9 $ (19,094.2 ) (d) (e) $ 59,544.6 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Appalachian Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2016 , 2015 and 2014 and reportable segment balance sheet information as of December 31, 2016 and 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (d) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (d) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (d) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (d) 16,397.3 Total Property, Plant and Equipment – Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (d) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (d) (e) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (d) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 20,242.2 $ (19,573.0 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees $ 31.9 $ 0.9 $ 630.8 $ 0.1 $ 56.8 $ — $ 720.5 Long-term Debt Due Within One Year: Non-Affiliated $ 935.4 $ 824.7 $ — $ 71.6 $ 0.1 $ — $ 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 10.1 — 4.7 8.6 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 280.3 23.5 45.3 25.1 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.7 62.9 179.3 15.2 — 902.6 Income from Continuing Operations $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 8.3 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 55.8 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Assets $ 33,705.1 $ 14,524.6 $ 3,570.0 $ 6,326.2 $ 20,512.9 $ (19,094.2 ) (d) (e) $ 59,544.6 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Indiana Michigan Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2016 , 2015 and 2014 and reportable segment balance sheet information as of December 31, 2016 and 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (d) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (d) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (d) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (d) 16,397.3 Total Property, Plant and Equipment – Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (d) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (d) (e) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (d) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 20,242.2 $ (19,573.0 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees $ 31.9 $ 0.9 $ 630.8 $ 0.1 $ 56.8 $ — $ 720.5 Long-term Debt Due Within One Year: Non-Affiliated $ 935.4 $ 824.7 $ — $ 71.6 $ 0.1 $ — $ 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 10.1 — 4.7 8.6 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 280.3 23.5 45.3 25.1 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.7 62.9 179.3 15.2 — 902.6 Income from Continuing Operations $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 8.3 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 55.8 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Assets $ 33,705.1 $ 14,524.6 $ 3,570.0 $ 6,326.2 $ 20,512.9 $ (19,094.2 ) (d) (e) $ 59,544.6 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Ohio Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2016 , 2015 and 2014 and reportable segment balance sheet information as of December 31, 2016 and 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (d) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (d) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (d) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (d) 16,397.3 Total Property, Plant and Equipment – Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (d) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (d) (e) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (d) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 20,242.2 $ (19,573.0 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees $ 31.9 $ 0.9 $ 630.8 $ 0.1 $ 56.8 $ — $ 720.5 Long-term Debt Due Within One Year: Non-Affiliated $ 935.4 $ 824.7 $ — $ 71.6 $ 0.1 $ — $ 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 10.1 — 4.7 8.6 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 280.3 23.5 45.3 25.1 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.7 62.9 179.3 15.2 — 902.6 Income from Continuing Operations $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 8.3 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 55.8 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Assets $ 33,705.1 $ 14,524.6 $ 3,570.0 $ 6,326.2 $ 20,512.9 $ (19,094.2 ) (d) (e) $ 59,544.6 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Public Service Co Of Oklahoma [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2016 , 2015 and 2014 and reportable segment balance sheet information as of December 31, 2016 and 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (d) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (d) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (d) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (d) 16,397.3 Total Property, Plant and Equipment – Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (d) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (d) (e) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (d) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 20,242.2 $ (19,573.0 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees $ 31.9 $ 0.9 $ 630.8 $ 0.1 $ 56.8 $ — $ 720.5 Long-term Debt Due Within One Year: Non-Affiliated $ 935.4 $ 824.7 $ — $ 71.6 $ 0.1 $ — $ 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 10.1 — 4.7 8.6 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 280.3 23.5 45.3 25.1 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.7 62.9 179.3 15.2 — 902.6 Income from Continuing Operations $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 8.3 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 55.8 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Assets $ 33,705.1 $ 14,524.6 $ 3,570.0 $ 6,326.2 $ 20,512.9 $ (19,094.2 ) (d) (e) $ 59,544.6 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Southwestern Electric Power Co [Member]
Business Segments	BUSINESS SEGMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. AEP’s Reportable Segments AEP’s primary business is the generation, transmission and distribution of electricity. Within its Vertically Integrated Utilities segment, AEP centrally dispatches generation assets and manages its overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. AEP’s reportable segments and their related business activities are outlined below: Vertically Integrated Utilities • Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo. Transmission and Distribution Utilities • Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo and AEP Texas. • OPCo purchases energy and capacity to serve SSO customers and provides transmission and distribution services for all connected load. • With the merger of TCC and TNC into AEP Utilities, Inc. to form AEP Texas, the Transmission and Distribution segment now includes certain activities related to the former AEP Utilities, Inc. that had been included in Corporate and Other. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in AEP’s wholly-owned transmission-only subsidiaries and transmission-only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity. Generation & Marketing • Competitive generation in ERCOT and PJM. • Marketing, risk management and retail activities in ERCOT, PJM, SPP and MISO. • Contracted renewable energy investments and management services. The remainder of AEP’s activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries, Parent’s guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. With the sale of AEPRO in November 2015, the activities related to the AEP River Operations segment have been moved to Corporate and Other for the periods presented. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The tables below present AEP’s reportable segment income statement information for the years ended December 31, 2016 , 2015 and 2014 and reportable segment balance sheet information as of December 31, 2016 and 2015 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (d) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (d) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (d) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (d) 16,397.3 Total Property, Plant and Equipment – Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (d) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (d) (e) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (d) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 20,242.2 $ (19,573.0 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees $ 31.9 $ 0.9 $ 630.8 $ 0.1 $ 56.8 $ — $ 720.5 Long-term Debt Due Within One Year: Non-Affiliated $ 935.4 $ 824.7 $ — $ 71.6 $ 0.1 $ — $ 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 10.1 — 4.7 8.6 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 280.3 23.5 45.3 25.1 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.7 62.9 179.3 15.2 — 902.6 Income from Continuing Operations $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 8.3 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 55.8 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Assets $ 33,705.1 $ 14,524.6 $ 3,570.0 $ 6,326.2 $ 20,512.9 $ (19,094.2 ) (d) (e) $ 59,544.6 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies. Registrant Subsidiaries’ Reportable Segments The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business for APCo, I&M, PSO and SWEPCo, and an electricity transmission and distribution business for OPCo. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

Derivatives and Hedging

Derivatives and Hedging	12 Months Ended
	Dec. 31, 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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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 December 31, 2016 and 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: December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets - Nonaffiliated 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities - Nonaffiliated 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 APCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets - Nonaffiliated 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities - Nonaffiliated 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 I&M Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ — $ — $ — 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 PSO Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.8 $ — $ 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (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. Certain 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 income. The following table shows the results of hedging gains (losses): Years Ended December 31, 2016 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1.6 $ 3.2 $ 3.8 Loss on Fair Value Portion of Long-term Debt (1.6 ) (3.3 ) (3.9 ) For 2016 , 2015 and 2014 , 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding power derivatives. During 2016 and 2015, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014 , APCo and I&M applied cash flow hedging to outstanding power derivatives. 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2016 December 31, 2015 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 11.2 $ — $ 17.6 $ — Hedging Liabilities (a) 46.7 — 26.1 0.4 AOCI Gain (Loss) Net of Tax (23.1 ) (15.7 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4.3 (1.0 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of December 31, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 132 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (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 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. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts. 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 t
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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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 December 31, 2016 and 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: December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets - Nonaffiliated 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities - Nonaffiliated 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 APCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets - Nonaffiliated 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities - Nonaffiliated 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 I&M Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ — $ — $ — 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 PSO Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.8 $ — $ 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (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. Certain 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 income. The following table shows the results of hedging gains (losses): Years Ended December 31, 2016 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1.6 $ 3.2 $ 3.8 Loss on Fair Value Portion of Long-term Debt (1.6 ) (3.3 ) (3.9 ) For 2016 , 2015 and 2014 , 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding power derivatives. During 2016 and 2015, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014 , APCo and I&M applied cash flow hedging to outstanding power derivatives. 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2016 December 31, 2015 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 11.2 $ — $ 17.6 $ — Hedging Liabilities (a) 46.7 — 26.1 0.4 AOCI Gain (Loss) Net of Tax (23.1 ) (15.7 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4.3 (1.0 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of December 31, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 132 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (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 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. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts. 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 t
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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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 December 31, 2016 and 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: December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets - Nonaffiliated 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities - Nonaffiliated 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 APCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets - Nonaffiliated 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities - Nonaffiliated 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 I&M Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ — $ — $ — 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 PSO Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.8 $ — $ 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (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. Certain 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 income. The following table shows the results of hedging gains (losses): Years Ended December 31, 2016 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1.6 $ 3.2 $ 3.8 Loss on Fair Value Portion of Long-term Debt (1.6 ) (3.3 ) (3.9 ) For 2016 , 2015 and 2014 , 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding power derivatives. During 2016 and 2015, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014 , APCo and I&M applied cash flow hedging to outstanding power derivatives. 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2016 December 31, 2015 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 11.2 $ — $ 17.6 $ — Hedging Liabilities (a) 46.7 — 26.1 0.4 AOCI Gain (Loss) Net of Tax (23.1 ) (15.7 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4.3 (1.0 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of December 31, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 132 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (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 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. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts. 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 t
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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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 December 31, 2016 and 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: December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets - Nonaffiliated 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities - Nonaffiliated 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 APCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets - Nonaffiliated 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities - Nonaffiliated 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 I&M Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ — $ — $ — 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 PSO Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.8 $ — $ 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (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. Certain 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 income. The following table shows the results of hedging gains (losses): Years Ended December 31, 2016 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1.6 $ 3.2 $ 3.8 Loss on Fair Value Portion of Long-term Debt (1.6 ) (3.3 ) (3.9 ) For 2016 , 2015 and 2014 , 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding power derivatives. During 2016 and 2015, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014 , APCo and I&M applied cash flow hedging to outstanding power derivatives. 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2016 December 31, 2015 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 11.2 $ — $ 17.6 $ — Hedging Liabilities (a) 46.7 — 26.1 0.4 AOCI Gain (Loss) Net of Tax (23.1 ) (15.7 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4.3 (1.0 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of December 31, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 132 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (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 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. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts. 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 t
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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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 December 31, 2016 and 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: December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets - Nonaffiliated 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities - Nonaffiliated 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 APCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets - Nonaffiliated 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities - Nonaffiliated 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 I&M Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ — $ — $ — 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 PSO Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.8 $ — $ 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (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. Certain 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 income. The following table shows the results of hedging gains (losses): Years Ended December 31, 2016 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1.6 $ 3.2 $ 3.8 Loss on Fair Value Portion of Long-term Debt (1.6 ) (3.3 ) (3.9 ) For 2016 , 2015 and 2014 , 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding power derivatives. During 2016 and 2015, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014 , APCo and I&M applied cash flow hedging to outstanding power derivatives. 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2016 December 31, 2015 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 11.2 $ — $ 17.6 $ — Hedging Liabilities (a) 46.7 — 26.1 0.4 AOCI Gain (Loss) Net of Tax (23.1 ) (15.7 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4.3 (1.0 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of December 31, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 132 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (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 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. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts. 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 t
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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The following tables represent the gross notional volume of the Registrants’ outstanding derivative contracts: Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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 December 31, 2016 and 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: December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3 The following tables represent the gross fair value of the Registrants’ derivative activity on the balance sheets: AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets - Nonaffiliated 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities - Nonaffiliated 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 APCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. I&M Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets - Nonaffiliated 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities - Nonaffiliated 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 I&M Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ — $ — $ — 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. PSO Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 PSO Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.8 $ — $ 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position. The tables below present the Registrants’ activity of derivative risk management contracts: Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (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. Certain 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 income. The following table shows the results of hedging gains (losses): Years Ended December 31, 2016 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1.6 $ 3.2 $ 3.8 Loss on Fair Value Portion of Long-term Debt (1.6 ) (3.3 ) (3.9 ) For 2016 , 2015 and 2014 , 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding power derivatives. During 2016 and 2015, the Registrant Subsidiaries did not apply cash flow hedging to outstanding power derivatives. During 2014 , APCo and I&M applied cash flow hedging to outstanding power derivatives. 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 2016 , 2015 and 2014 , AEP applied cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , the Registrant Subsidiaries did not apply cash flow hedging to outstanding interest rate derivatives. During 2016 , 2015 and 2014 , hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above. For details on effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets and the reasons for changes in cash flow hedges, see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the balance sheets were: Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2016 December 31, 2015 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 11.2 $ — $ 17.6 $ — Hedging Liabilities (a) 46.7 — 26.1 0.4 AOCI Gain (Loss) Net of Tax (23.1 ) (15.7 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4.3 (1.0 ) (0.4 ) (1.5 ) (a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the balance sheets. As of December 31, 2016 the maximum length of time that AEP is hedging its exposure to variability in future cash flows related to forecasted transactions is 132 months. Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (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 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. There is no exposure relating to derivative contracts, however, there is exposure relating to RTOs, ISOs and non-derivative contracts. The following table represents the exposure if credit ratings were to decline below a specified rating threshold: December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts. 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

Fair Value Measurements

Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2016 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (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: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 2.3 10.7 1.6 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2016 , 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments: December 31, 2016 2015 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 18.7 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 785.4 27.1 (5.5 ) 731.1 35.9 (2.6 ) Corporate Debt 60.9 2.3 (1.4 ) 57.9 3.2 (1.1 ) State and Local Government 121.1 0.4 (0.7 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 967.4 29.8 (7.6 ) 811.2 40.2 (4.0 ) Equity Securities – Domestic 1,270.1 677.9 (79.6 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,256.2 $ 707.7 $ (87.2 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ 2,957.7 $ 2,218.4 $ 1,031.8 Purchases of Investments 3,000.0 2,272.0 1,086.4 Gross Realized Gains on Investment Sales 46.1 69.1 32.3 Gross Realized Losses on Investment Sales 24.4 53.0 15.4 The base cost of fixed income securities was $938 million and $771 million as of December 31, 2016 and 2015 , respectively. The base cost of equity securities was $592 million and $555 million as of December 31, 2016 and 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 229.5 1 year – 5 years 335.3 5 years – 10 years 204.6 After 10 years 198.0 Total $ 967.4 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 years ended December 31, 2016 , 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 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) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs 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 December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs 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 December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs 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 December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs 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 December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs 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 Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) 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. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2016 and 2015 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Appalachian Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2016 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (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: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 2.3 10.7 1.6 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2016 , 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments: December 31, 2016 2015 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 18.7 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 785.4 27.1 (5.5 ) 731.1 35.9 (2.6 ) Corporate Debt 60.9 2.3 (1.4 ) 57.9 3.2 (1.1 ) State and Local Government 121.1 0.4 (0.7 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 967.4 29.8 (7.6 ) 811.2 40.2 (4.0 ) Equity Securities – Domestic 1,270.1 677.9 (79.6 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,256.2 $ 707.7 $ (87.2 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ 2,957.7 $ 2,218.4 $ 1,031.8 Purchases of Investments 3,000.0 2,272.0 1,086.4 Gross Realized Gains on Investment Sales 46.1 69.1 32.3 Gross Realized Losses on Investment Sales 24.4 53.0 15.4 The base cost of fixed income securities was $938 million and $771 million as of December 31, 2016 and 2015 , respectively. The base cost of equity securities was $592 million and $555 million as of December 31, 2016 and 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 229.5 1 year – 5 years 335.3 5 years – 10 years 204.6 After 10 years 198.0 Total $ 967.4 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 years ended December 31, 2016 , 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 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) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs 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 December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs 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 December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs 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 December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs 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 December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs 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 Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) 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. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2016 and 2015 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2016 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (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: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 2.3 10.7 1.6 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2016 , 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments: December 31, 2016 2015 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 18.7 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 785.4 27.1 (5.5 ) 731.1 35.9 (2.6 ) Corporate Debt 60.9 2.3 (1.4 ) 57.9 3.2 (1.1 ) State and Local Government 121.1 0.4 (0.7 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 967.4 29.8 (7.6 ) 811.2 40.2 (4.0 ) Equity Securities – Domestic 1,270.1 677.9 (79.6 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,256.2 $ 707.7 $ (87.2 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ 2,957.7 $ 2,218.4 $ 1,031.8 Purchases of Investments 3,000.0 2,272.0 1,086.4 Gross Realized Gains on Investment Sales 46.1 69.1 32.3 Gross Realized Losses on Investment Sales 24.4 53.0 15.4 The base cost of fixed income securities was $938 million and $771 million as of December 31, 2016 and 2015 , respectively. The base cost of equity securities was $592 million and $555 million as of December 31, 2016 and 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 229.5 1 year – 5 years 335.3 5 years – 10 years 204.6 After 10 years 198.0 Total $ 967.4 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 years ended December 31, 2016 , 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 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) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs 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 December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs 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 December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs 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 December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs 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 December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs 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 Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) 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. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2016 and 2015 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Ohio Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2016 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (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: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 2.3 10.7 1.6 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2016 , 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments: December 31, 2016 2015 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 18.7 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 785.4 27.1 (5.5 ) 731.1 35.9 (2.6 ) Corporate Debt 60.9 2.3 (1.4 ) 57.9 3.2 (1.1 ) State and Local Government 121.1 0.4 (0.7 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 967.4 29.8 (7.6 ) 811.2 40.2 (4.0 ) Equity Securities – Domestic 1,270.1 677.9 (79.6 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,256.2 $ 707.7 $ (87.2 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ 2,957.7 $ 2,218.4 $ 1,031.8 Purchases of Investments 3,000.0 2,272.0 1,086.4 Gross Realized Gains on Investment Sales 46.1 69.1 32.3 Gross Realized Losses on Investment Sales 24.4 53.0 15.4 The base cost of fixed income securities was $938 million and $771 million as of December 31, 2016 and 2015 , respectively. The base cost of equity securities was $592 million and $555 million as of December 31, 2016 and 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 229.5 1 year – 5 years 335.3 5 years – 10 years 204.6 After 10 years 198.0 Total $ 967.4 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 years ended December 31, 2016 , 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 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) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs 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 December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs 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 December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs 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 December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs 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 December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs 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 Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) 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. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2016 and 2015 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2016 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (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: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 2.3 10.7 1.6 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2016 , 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments: December 31, 2016 2015 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 18.7 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 785.4 27.1 (5.5 ) 731.1 35.9 (2.6 ) Corporate Debt 60.9 2.3 (1.4 ) 57.9 3.2 (1.1 ) State and Local Government 121.1 0.4 (0.7 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 967.4 29.8 (7.6 ) 811.2 40.2 (4.0 ) Equity Securities – Domestic 1,270.1 677.9 (79.6 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,256.2 $ 707.7 $ (87.2 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ 2,957.7 $ 2,218.4 $ 1,031.8 Purchases of Investments 3,000.0 2,272.0 1,086.4 Gross Realized Gains on Investment Sales 46.1 69.1 32.3 Gross Realized Losses on Investment Sales 24.4 53.0 15.4 The base cost of fixed income securities was $938 million and $771 million as of December 31, 2016 and 2015 , respectively. The base cost of equity securities was $592 million and $555 million as of December 31, 2016 and 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 229.5 1 year – 5 years 335.3 5 years – 10 years 204.6 After 10 years 198.0 Total $ 967.4 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 years ended December 31, 2016 , 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 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) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs 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 December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs 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 December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs 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 December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs 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 December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs 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 Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) 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. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2016 and 2015 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS The disclosures in this note apply to all Registrants unless indicated otherwise. Fair Value Measurements of Long-term Debt The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange. The book values and fair values of Long-term Debt are summarized in the following table: December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. Fair Value Measurements of Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by AEP’s protected cell of EIS. See “Other Temporary Investments” section of Note 1 . The following is a summary of Other Temporary Investments: December 31, 2016 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (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: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 2.3 10.7 1.6 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — — For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the years ended December 31, 2016 , 2015 and 2014 , see Note 3 . Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal (Applies to AEP and I&M) Securities held in trust funds for decommissioning nuclear facilities and for the disposal of SNF are recorded at fair value. See “Nuclear Trust Funds” section of Note 1 . The following is a summary of nuclear trust fund investments: December 31, 2016 2015 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 18.7 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 785.4 27.1 (5.5 ) 731.1 35.9 (2.6 ) Corporate Debt 60.9 2.3 (1.4 ) 57.9 3.2 (1.1 ) State and Local Government 121.1 0.4 (0.7 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 967.4 29.8 (7.6 ) 811.2 40.2 (4.0 ) Equity Securities – Domestic 1,270.1 677.9 (79.6 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,256.2 $ 707.7 $ (87.2 ) $ 2,106.4 $ 611.8 $ (83.3 ) The following table provides the securities activity within the decommissioning and SNF trusts: Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ 2,957.7 $ 2,218.4 $ 1,031.8 Purchases of Investments 3,000.0 2,272.0 1,086.4 Gross Realized Gains on Investment Sales 46.1 69.1 32.3 Gross Realized Losses on Investment Sales 24.4 53.0 15.4 The base cost of fixed income securities was $938 million and $771 million as of December 31, 2016 and 2015 , respectively. The base cost of equity securities was $592 million and $555 million as of December 31, 2016 and 2015 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of December 31, 2016 was as follows: Fair Value of Fixed Income Securities (in millions) Within 1 year $ 229.5 1 year – 5 years 335.3 5 years – 10 years 204.6 After 10 years 198.0 Total $ 967.4 Fair Value Measurements of Financial Assets and Liabilities For a discussion of fair value accounting and the classification of assets and liabilities within the fair value hierarchy, see the “Fair Value Measurements of Assets and Liabilities” section of Note 1 . The following tables set forth, by level within the fair value hierarchy, the Registrants’ financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. AEP Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 years ended December 31, 2016 , 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy: Year Ended December 31, 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) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities. The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions: Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs 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 December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs 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 December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs 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 December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs 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 December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs 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 Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) 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. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrants as of December 31, 2016 and 2015 : Sensitivity of Fair Value Measurements Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Income Tax Expense (Credit) The details of the Registrants’ income tax expense (credit) before discontinued operations as reported are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 AEP Years Ended December 31, 2015 2014 (in millions) Federal: Current $ 107.3 $ 22.8 Deferred 774.8 800.1 Total Federal 882.1 822.9 State and Local: Current 14.5 22.8 Deferred 23.0 56.9 Total State and Local 37.5 79.7 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 618.0 $ 2,052.3 $ 1,638.0 Discontinued Operations (Net of Income Tax of $0, $6.2 and $39 in 2016, 2015 and 2014, Respectively) 2.5 (283.7 ) (47.5 ) Income Tax Expense (Credit) Before Discontinued Operations (73.7 ) 919.6 902.6 Pretax Income $ 546.8 $ 2,688.2 $ 2,493.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 191.4 $ 940.9 $ 872.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 41.7 53.6 54.0 Investment Tax Credits, Net (12.3 ) (11.6 ) (12.8 ) State and Local Income Taxes, Net (20.7 ) 24.4 54.3 Removal Costs (39.8 ) (28.8 ) (23.9 ) AFUDC (44.8 ) (51.6 ) (41.8 ) Valuation Allowance (128.3 ) 17.2 (2.5 ) U.K. Windfall Tax (12.9 ) — — Tax Adjustments (43.9 ) (20.1 ) (10.1 ) Other (4.1 ) (4.4 ) 12.8 Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 919.6 $ 902.6 Effective Income Tax Rate (13.5 ) % 34.2 % 36.2 % APCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 369.1 $ 340.6 $ 215.4 Income Tax Expense 199.1 194.3 154.9 Pretax Income $ 568.2 $ 534.9 $ 370.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 198.9 $ 187.2 $ 129.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.3 19.8 23.5 Investment Tax Credits, Net (0.1 ) (0.3 ) (0.6 ) State and Local Income Taxes, Net 6.0 7.2 6.5 Removal Costs (12.0 ) (9.9 ) (6.8 ) AFUDC (6.1 ) (7.0 ) (3.8 ) Valuation Allowance (1.7 ) 1.7 (2.5 ) Other (5.2 ) (4.4 ) 9.0 Income Tax Expense $ 199.1 $ 194.3 $ 154.9 Effective Income Tax Rate 35.0 % 36.3 % 41.8 % I&M Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 239.9 $ 204.8 $ 155.6 Income Tax Expense 67.5 96.1 79.6 Pretax Income $ 307.4 $ 300.9 $ 235.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 107.6 $ 105.3 $ 82.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 6.7 9.5 12.9 Investment Tax Credits, Net (4.7 ) (3.3 ) (4.9 ) State and Local Income Taxes, Net 2.4 5.8 7.7 Removal Costs (21.3 ) (12.6 ) (11.3 ) AFUDC (7.3 ) (6.2 ) (10.0 ) Tax Adjustments (14.2 ) (4.2 ) 1.2 Other (1.7 ) 1.8 1.7 Income Tax Expense $ 67.5 $ 96.1 $ 79.6 Effective Income Tax Rate 22.0 % 31.9 % 33.8 % OPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 282.2 $ 232.7 $ 216.4 Income Tax Expense 143.8 126.5 132.2 Pretax Income $ 426.0 $ 359.2 $ 348.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 149.1 $ 125.7 $ 122.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.1 8.2 6.7 Investment Tax Credits, Net — (0.1 ) (0.2 ) State and Local Income Taxes, Net 3.8 0.7 8.8 Other (16.2 ) (8.0 ) (5.1 ) Income Tax Expense $ 143.8 $ 126.5 $ 132.2 Effective Income Tax Rate 33.8 % 35.2 % 37.9 % PSO Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 100.0 $ 92.5 $ 86.9 Income Tax Expense 54.4 51.3 50.6 Pretax Income $ 154.4 $ 143.8 $ 137.5 Income Taxes on Pretax Income at Statutory Rate (35%) $ 54.0 $ 50.3 $ 48.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.8 0.5 0.2 Investment Tax Credits, Net (1.4 ) (1.8 ) (0.8 ) State and Local Income Taxes, Net 4.2 5.1 4.8 AFUDC (2.2 ) (3.1 ) (1.1 ) Other (1.0 ) 0.3 (0.6 ) Income Tax Expense $ 54.4 $ 51.3 $ 50.6 Effective Income Tax Rate 35.2 % 35.7 % 36.8 % SWEPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 169.7 $ 196.0 $ 144.6 Income Tax Expense 52.1 84.8 66.4 Pretax Income $ 221.8 $ 280.8 $ 211.0 Income Taxes on Pretax Income at Statutory Rate (35%) $ 77.6 $ 98.3 $ 73.8 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.2 3.1 2.9 Depletion (5.5 ) (5.5 ) (4.1 ) Investment Tax Credits, Net (1.2 ) (1.4 ) (1.4 ) State and Local Income Taxes, Net (14.7 ) 4.8 3.1 AFUDC (3.9 ) (9.2 ) (4.2 ) Other (3.4 ) (5.3 ) (3.7 ) Income Tax Expense $ 52.1 $ 84.8 $ 66.4 Effective Income Tax Rate 23.5 % 30.2 % 31.5 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2016 2015 (in millions) Deferred Tax Assets $ 2,753.0 $ 2,503.9 Deferred Tax Liabilities (14,637.4 ) (14,237.1 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) Property Related Temporary Differences $ (8,758.1 ) $ (8,533.3 ) Amounts Due from Customers for Future Federal Income Taxes (292.2 ) (263.5 ) Deferred State Income Taxes (976.6 ) (872.0 ) Securitized Assets (535.6 ) (633.2 ) Regulatory Assets (896.9 ) (873.6 ) Deferred Income Taxes on Other Comprehensive Loss 88.7 72.2 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Net Operating Loss Carryforward 101.2 39.6 Tax Credit Carryforward 45.1 85.0 Valuation Allowance (1.8 ) (130.0 ) All Other, Net 8.6 (9.8 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) APCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 413.5 $ 412.9 Deferred Tax Liabilities (3,085.8 ) (2,939.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) Property Related Temporary Differences $ (2,031.9 ) $ (1,866.0 ) Amounts Due from Customers for Future Federal Income Taxes (73.1 ) (68.2 ) Deferred State Income Taxes (319.3 ) (308.7 ) Regulatory Assets (159.9 ) (169.1 ) Securitized Assets (106.9 ) (114.8 ) Deferred Income Taxes on Other Comprehensive Loss 4.5 1.5 Tax Credit Carryforward 11.7 19.2 All Other, Net 2.6 (20.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) I&M December 31, 2016 2015 (in millions) Deferred Tax Assets $ 912.9 $ 837.4 Deferred Tax Liabilities (2,440.3 ) (2,198.9 ) Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) Property Related Temporary Differences $ (579.4 ) $ (521.6 ) Amounts Due from Customers for Future Federal Income Taxes (50.4 ) (42.7 ) Deferred State Income Taxes (158.7 ) (124.8 ) Deferred Income Taxes on Other Comprehensive Loss 8.8 9.0 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Regulatory Assets (81.0 ) (70.2 ) Net Operating Loss Carryforward 7.1 — All Other, Net (7.0 ) 3.4 Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) OPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 232.4 $ 162.4 Deferred Tax Liabilities (1,578.5 ) (1,545.6 ) Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) Property Related Temporary Differences $ (1,090.8 ) $ (1,022.8 ) Amounts Due from Customers for Future Federal Income Taxes (43.6 ) (44.6 ) Deferred State Income Taxes (34.6 ) (34.4 ) Regulatory Assets (174.1 ) (220.0 ) Deferred Income Taxes on Other Comprehensive Loss (1.6 ) (2.3 ) Deferred Fuel and Purchased Power (117.6 ) (117.4 ) All Other, Net 116.2 58.3 Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) PSO December 31, 2016 2015 (in millions) Deferred Tax Assets $ 153.8 $ 141.2 Deferred Tax Liabilities (1,212.6 ) (1,113.0 ) Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) Property Related Temporary Differences $ (927.3 ) $ (861.9 ) Amounts Due from Customers for Future Federal Income Taxes (3.2 ) (2.2 ) Deferred State Income Taxes (128.5 ) (117.0 ) Regulatory Assets (67.6 ) (54.3 ) Deferred Income Taxes on Other Comprehensive Loss (1.8 ) (2.3 ) Deferred Federal Income Taxes on Deferred State Income Taxes 50.6 46.6 Net Operating Loss Carryforward 16.5 7.1 Tax Credit Carryforward — 0.6 All Other, Net 2.5 11.6 Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) SWEPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 230.5 $ 194.7 Deferred Tax Liabilities (1,837.4 ) (1,594.5 ) Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) Property Related Temporary Differences $ (1,445.2 ) $ (1,275.1 ) Amounts Due from Customers for Future Federal Income Taxes (48.2 ) (47.8 ) Deferred State Income Taxes (175.1 ) (132.3 ) Regulatory Assets (40.7 ) (26.1 ) Deferred Income Taxes on Other Comprehensive Loss 5.1 5.0 Impairment Loss - Turk Plant 20.3 20.7 Net Operating Loss Carryforward 40.3 19.7 Tax Credit Carryforward 0.1 0.7 All Other, Net 36.5 35.4 Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. As of December 31, 2015 there was a valuation allowance of $130 million recorded against AEP’s deferred tax asset balance. AEP recorded changes in the valuation allowance in the second quarter of 2016 related to the reversal of a $56 million unrealized capital loss where AEP effectively settled a 2011 audit issue with the IRS. AEP also recorded changes in the third quarter of 2016 by reducing the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets held for sale and the filing of the 2015 federal income tax return. The sale of these assets held for sale are expected to result in a gain, the character of which will allow AEP to recognize the capital loss and allowed AEP to reverse substantially all of the remaining capital loss valuation allowance previously recorded. During the fourth quarter of 2016, AEP reversed $6 million of the valuation allowance associated with charitable contributions that expired at the end of the year. As of December 31, 2016 there was a valuation allowance of $2 million recorded against AEP’s deferred tax asset balance related to an unrealized capital loss carryforward. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine their tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. Net Income Tax Operating Loss Carryforward In 2016, AEP, I&M, PSO and SWEPCo recognized federal net income tax operating losses of $143 million , $20 million , $17 million and $37 million , respectively, which were driven primarily by bonus depreciation. As of December 31, 2016, AEP, I&M, PSO and SWEPCo had $50 million , $7 million , $6 million and $13 million , respectively, of unrealized federal net operating loss carryforward tax benefits. Management anticipates future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2036 . AEP, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2016 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036 Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2016 and 2015, AEP had $17 million and $59 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2016, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2032 through 2036 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. In the first quarter of 2017, AEP received the tax refund related to the U.K. Windfall Tax, including interest through the date of the refund. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2 The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties: Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9 Federal Tax Legislation The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. Additional legislation was passed by the state of Indiana reducing the corporate income tax rate from 6.5% in 2016 to 4.9% beginning after June 30, 2016 with the final reduction occurring in years beginning after June 30, 2021. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrants’ net income, cash flows, or financial condition. 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 income/franchise 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 in 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 the Registrants’ net income, cash flows or financial condition.
Appalachian Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Income Tax Expense (Credit) The details of the Registrants’ income tax expense (credit) before discontinued operations as reported are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 AEP Years Ended December 31, 2015 2014 (in millions) Federal: Current $ 107.3 $ 22.8 Deferred 774.8 800.1 Total Federal 882.1 822.9 State and Local: Current 14.5 22.8 Deferred 23.0 56.9 Total State and Local 37.5 79.7 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 618.0 $ 2,052.3 $ 1,638.0 Discontinued Operations (Net of Income Tax of $0, $6.2 and $39 in 2016, 2015 and 2014, Respectively) 2.5 (283.7 ) (47.5 ) Income Tax Expense (Credit) Before Discontinued Operations (73.7 ) 919.6 902.6 Pretax Income $ 546.8 $ 2,688.2 $ 2,493.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 191.4 $ 940.9 $ 872.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 41.7 53.6 54.0 Investment Tax Credits, Net (12.3 ) (11.6 ) (12.8 ) State and Local Income Taxes, Net (20.7 ) 24.4 54.3 Removal Costs (39.8 ) (28.8 ) (23.9 ) AFUDC (44.8 ) (51.6 ) (41.8 ) Valuation Allowance (128.3 ) 17.2 (2.5 ) U.K. Windfall Tax (12.9 ) — — Tax Adjustments (43.9 ) (20.1 ) (10.1 ) Other (4.1 ) (4.4 ) 12.8 Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 919.6 $ 902.6 Effective Income Tax Rate (13.5 ) % 34.2 % 36.2 % APCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 369.1 $ 340.6 $ 215.4 Income Tax Expense 199.1 194.3 154.9 Pretax Income $ 568.2 $ 534.9 $ 370.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 198.9 $ 187.2 $ 129.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.3 19.8 23.5 Investment Tax Credits, Net (0.1 ) (0.3 ) (0.6 ) State and Local Income Taxes, Net 6.0 7.2 6.5 Removal Costs (12.0 ) (9.9 ) (6.8 ) AFUDC (6.1 ) (7.0 ) (3.8 ) Valuation Allowance (1.7 ) 1.7 (2.5 ) Other (5.2 ) (4.4 ) 9.0 Income Tax Expense $ 199.1 $ 194.3 $ 154.9 Effective Income Tax Rate 35.0 % 36.3 % 41.8 % I&M Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 239.9 $ 204.8 $ 155.6 Income Tax Expense 67.5 96.1 79.6 Pretax Income $ 307.4 $ 300.9 $ 235.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 107.6 $ 105.3 $ 82.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 6.7 9.5 12.9 Investment Tax Credits, Net (4.7 ) (3.3 ) (4.9 ) State and Local Income Taxes, Net 2.4 5.8 7.7 Removal Costs (21.3 ) (12.6 ) (11.3 ) AFUDC (7.3 ) (6.2 ) (10.0 ) Tax Adjustments (14.2 ) (4.2 ) 1.2 Other (1.7 ) 1.8 1.7 Income Tax Expense $ 67.5 $ 96.1 $ 79.6 Effective Income Tax Rate 22.0 % 31.9 % 33.8 % OPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 282.2 $ 232.7 $ 216.4 Income Tax Expense 143.8 126.5 132.2 Pretax Income $ 426.0 $ 359.2 $ 348.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 149.1 $ 125.7 $ 122.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.1 8.2 6.7 Investment Tax Credits, Net — (0.1 ) (0.2 ) State and Local Income Taxes, Net 3.8 0.7 8.8 Other (16.2 ) (8.0 ) (5.1 ) Income Tax Expense $ 143.8 $ 126.5 $ 132.2 Effective Income Tax Rate 33.8 % 35.2 % 37.9 % PSO Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 100.0 $ 92.5 $ 86.9 Income Tax Expense 54.4 51.3 50.6 Pretax Income $ 154.4 $ 143.8 $ 137.5 Income Taxes on Pretax Income at Statutory Rate (35%) $ 54.0 $ 50.3 $ 48.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.8 0.5 0.2 Investment Tax Credits, Net (1.4 ) (1.8 ) (0.8 ) State and Local Income Taxes, Net 4.2 5.1 4.8 AFUDC (2.2 ) (3.1 ) (1.1 ) Other (1.0 ) 0.3 (0.6 ) Income Tax Expense $ 54.4 $ 51.3 $ 50.6 Effective Income Tax Rate 35.2 % 35.7 % 36.8 % SWEPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 169.7 $ 196.0 $ 144.6 Income Tax Expense 52.1 84.8 66.4 Pretax Income $ 221.8 $ 280.8 $ 211.0 Income Taxes on Pretax Income at Statutory Rate (35%) $ 77.6 $ 98.3 $ 73.8 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.2 3.1 2.9 Depletion (5.5 ) (5.5 ) (4.1 ) Investment Tax Credits, Net (1.2 ) (1.4 ) (1.4 ) State and Local Income Taxes, Net (14.7 ) 4.8 3.1 AFUDC (3.9 ) (9.2 ) (4.2 ) Other (3.4 ) (5.3 ) (3.7 ) Income Tax Expense $ 52.1 $ 84.8 $ 66.4 Effective Income Tax Rate 23.5 % 30.2 % 31.5 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2016 2015 (in millions) Deferred Tax Assets $ 2,753.0 $ 2,503.9 Deferred Tax Liabilities (14,637.4 ) (14,237.1 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) Property Related Temporary Differences $ (8,758.1 ) $ (8,533.3 ) Amounts Due from Customers for Future Federal Income Taxes (292.2 ) (263.5 ) Deferred State Income Taxes (976.6 ) (872.0 ) Securitized Assets (535.6 ) (633.2 ) Regulatory Assets (896.9 ) (873.6 ) Deferred Income Taxes on Other Comprehensive Loss 88.7 72.2 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Net Operating Loss Carryforward 101.2 39.6 Tax Credit Carryforward 45.1 85.0 Valuation Allowance (1.8 ) (130.0 ) All Other, Net 8.6 (9.8 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) APCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 413.5 $ 412.9 Deferred Tax Liabilities (3,085.8 ) (2,939.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) Property Related Temporary Differences $ (2,031.9 ) $ (1,866.0 ) Amounts Due from Customers for Future Federal Income Taxes (73.1 ) (68.2 ) Deferred State Income Taxes (319.3 ) (308.7 ) Regulatory Assets (159.9 ) (169.1 ) Securitized Assets (106.9 ) (114.8 ) Deferred Income Taxes on Other Comprehensive Loss 4.5 1.5 Tax Credit Carryforward 11.7 19.2 All Other, Net 2.6 (20.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) I&M December 31, 2016 2015 (in millions) Deferred Tax Assets $ 912.9 $ 837.4 Deferred Tax Liabilities (2,440.3 ) (2,198.9 ) Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) Property Related Temporary Differences $ (579.4 ) $ (521.6 ) Amounts Due from Customers for Future Federal Income Taxes (50.4 ) (42.7 ) Deferred State Income Taxes (158.7 ) (124.8 ) Deferred Income Taxes on Other Comprehensive Loss 8.8 9.0 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Regulatory Assets (81.0 ) (70.2 ) Net Operating Loss Carryforward 7.1 — All Other, Net (7.0 ) 3.4 Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) OPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 232.4 $ 162.4 Deferred Tax Liabilities (1,578.5 ) (1,545.6 ) Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) Property Related Temporary Differences $ (1,090.8 ) $ (1,022.8 ) Amounts Due from Customers for Future Federal Income Taxes (43.6 ) (44.6 ) Deferred State Income Taxes (34.6 ) (34.4 ) Regulatory Assets (174.1 ) (220.0 ) Deferred Income Taxes on Other Comprehensive Loss (1.6 ) (2.3 ) Deferred Fuel and Purchased Power (117.6 ) (117.4 ) All Other, Net 116.2 58.3 Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) PSO December 31, 2016 2015 (in millions) Deferred Tax Assets $ 153.8 $ 141.2 Deferred Tax Liabilities (1,212.6 ) (1,113.0 ) Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) Property Related Temporary Differences $ (927.3 ) $ (861.9 ) Amounts Due from Customers for Future Federal Income Taxes (3.2 ) (2.2 ) Deferred State Income Taxes (128.5 ) (117.0 ) Regulatory Assets (67.6 ) (54.3 ) Deferred Income Taxes on Other Comprehensive Loss (1.8 ) (2.3 ) Deferred Federal Income Taxes on Deferred State Income Taxes 50.6 46.6 Net Operating Loss Carryforward 16.5 7.1 Tax Credit Carryforward — 0.6 All Other, Net 2.5 11.6 Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) SWEPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 230.5 $ 194.7 Deferred Tax Liabilities (1,837.4 ) (1,594.5 ) Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) Property Related Temporary Differences $ (1,445.2 ) $ (1,275.1 ) Amounts Due from Customers for Future Federal Income Taxes (48.2 ) (47.8 ) Deferred State Income Taxes (175.1 ) (132.3 ) Regulatory Assets (40.7 ) (26.1 ) Deferred Income Taxes on Other Comprehensive Loss 5.1 5.0 Impairment Loss - Turk Plant 20.3 20.7 Net Operating Loss Carryforward 40.3 19.7 Tax Credit Carryforward 0.1 0.7 All Other, Net 36.5 35.4 Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. As of December 31, 2015 there was a valuation allowance of $130 million recorded against AEP’s deferred tax asset balance. AEP recorded changes in the valuation allowance in the second quarter of 2016 related to the reversal of a $56 million unrealized capital loss where AEP effectively settled a 2011 audit issue with the IRS. AEP also recorded changes in the third quarter of 2016 by reducing the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets held for sale and the filing of the 2015 federal income tax return. The sale of these assets held for sale are expected to result in a gain, the character of which will allow AEP to recognize the capital loss and allowed AEP to reverse substantially all of the remaining capital loss valuation allowance previously recorded. During the fourth quarter of 2016, AEP reversed $6 million of the valuation allowance associated with charitable contributions that expired at the end of the year. As of December 31, 2016 there was a valuation allowance of $2 million recorded against AEP’s deferred tax asset balance related to an unrealized capital loss carryforward. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine their tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. Net Income Tax Operating Loss Carryforward In 2016, AEP, I&M, PSO and SWEPCo recognized federal net income tax operating losses of $143 million , $20 million , $17 million and $37 million , respectively, which were driven primarily by bonus depreciation. As of December 31, 2016, AEP, I&M, PSO and SWEPCo had $50 million , $7 million , $6 million and $13 million , respectively, of unrealized federal net operating loss carryforward tax benefits. Management anticipates future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2036 . AEP, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2016 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036 Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2016 and 2015, AEP had $17 million and $59 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2016, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2032 through 2036 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. In the first quarter of 2017, AEP received the tax refund related to the U.K. Windfall Tax, including interest through the date of the refund. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2 The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties: Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9 Federal Tax Legislation The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. Additional legislation was passed by the state of Indiana reducing the corporate income tax rate from 6.5% in 2016 to 4.9% beginning after June 30, 2016 with the final reduction occurring in years beginning after June 30, 2021. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrants’ net income, cash flows, or financial condition. 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 income/franchise 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 in 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 the Registrants’ net income, cash flows or financial condition.
Indiana Michigan Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Income Tax Expense (Credit) The details of the Registrants’ income tax expense (credit) before discontinued operations as reported are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 AEP Years Ended December 31, 2015 2014 (in millions) Federal: Current $ 107.3 $ 22.8 Deferred 774.8 800.1 Total Federal 882.1 822.9 State and Local: Current 14.5 22.8 Deferred 23.0 56.9 Total State and Local 37.5 79.7 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 618.0 $ 2,052.3 $ 1,638.0 Discontinued Operations (Net of Income Tax of $0, $6.2 and $39 in 2016, 2015 and 2014, Respectively) 2.5 (283.7 ) (47.5 ) Income Tax Expense (Credit) Before Discontinued Operations (73.7 ) 919.6 902.6 Pretax Income $ 546.8 $ 2,688.2 $ 2,493.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 191.4 $ 940.9 $ 872.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 41.7 53.6 54.0 Investment Tax Credits, Net (12.3 ) (11.6 ) (12.8 ) State and Local Income Taxes, Net (20.7 ) 24.4 54.3 Removal Costs (39.8 ) (28.8 ) (23.9 ) AFUDC (44.8 ) (51.6 ) (41.8 ) Valuation Allowance (128.3 ) 17.2 (2.5 ) U.K. Windfall Tax (12.9 ) — — Tax Adjustments (43.9 ) (20.1 ) (10.1 ) Other (4.1 ) (4.4 ) 12.8 Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 919.6 $ 902.6 Effective Income Tax Rate (13.5 ) % 34.2 % 36.2 % APCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 369.1 $ 340.6 $ 215.4 Income Tax Expense 199.1 194.3 154.9 Pretax Income $ 568.2 $ 534.9 $ 370.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 198.9 $ 187.2 $ 129.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.3 19.8 23.5 Investment Tax Credits, Net (0.1 ) (0.3 ) (0.6 ) State and Local Income Taxes, Net 6.0 7.2 6.5 Removal Costs (12.0 ) (9.9 ) (6.8 ) AFUDC (6.1 ) (7.0 ) (3.8 ) Valuation Allowance (1.7 ) 1.7 (2.5 ) Other (5.2 ) (4.4 ) 9.0 Income Tax Expense $ 199.1 $ 194.3 $ 154.9 Effective Income Tax Rate 35.0 % 36.3 % 41.8 % I&M Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 239.9 $ 204.8 $ 155.6 Income Tax Expense 67.5 96.1 79.6 Pretax Income $ 307.4 $ 300.9 $ 235.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 107.6 $ 105.3 $ 82.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 6.7 9.5 12.9 Investment Tax Credits, Net (4.7 ) (3.3 ) (4.9 ) State and Local Income Taxes, Net 2.4 5.8 7.7 Removal Costs (21.3 ) (12.6 ) (11.3 ) AFUDC (7.3 ) (6.2 ) (10.0 ) Tax Adjustments (14.2 ) (4.2 ) 1.2 Other (1.7 ) 1.8 1.7 Income Tax Expense $ 67.5 $ 96.1 $ 79.6 Effective Income Tax Rate 22.0 % 31.9 % 33.8 % OPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 282.2 $ 232.7 $ 216.4 Income Tax Expense 143.8 126.5 132.2 Pretax Income $ 426.0 $ 359.2 $ 348.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 149.1 $ 125.7 $ 122.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.1 8.2 6.7 Investment Tax Credits, Net — (0.1 ) (0.2 ) State and Local Income Taxes, Net 3.8 0.7 8.8 Other (16.2 ) (8.0 ) (5.1 ) Income Tax Expense $ 143.8 $ 126.5 $ 132.2 Effective Income Tax Rate 33.8 % 35.2 % 37.9 % PSO Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 100.0 $ 92.5 $ 86.9 Income Tax Expense 54.4 51.3 50.6 Pretax Income $ 154.4 $ 143.8 $ 137.5 Income Taxes on Pretax Income at Statutory Rate (35%) $ 54.0 $ 50.3 $ 48.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.8 0.5 0.2 Investment Tax Credits, Net (1.4 ) (1.8 ) (0.8 ) State and Local Income Taxes, Net 4.2 5.1 4.8 AFUDC (2.2 ) (3.1 ) (1.1 ) Other (1.0 ) 0.3 (0.6 ) Income Tax Expense $ 54.4 $ 51.3 $ 50.6 Effective Income Tax Rate 35.2 % 35.7 % 36.8 % SWEPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 169.7 $ 196.0 $ 144.6 Income Tax Expense 52.1 84.8 66.4 Pretax Income $ 221.8 $ 280.8 $ 211.0 Income Taxes on Pretax Income at Statutory Rate (35%) $ 77.6 $ 98.3 $ 73.8 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.2 3.1 2.9 Depletion (5.5 ) (5.5 ) (4.1 ) Investment Tax Credits, Net (1.2 ) (1.4 ) (1.4 ) State and Local Income Taxes, Net (14.7 ) 4.8 3.1 AFUDC (3.9 ) (9.2 ) (4.2 ) Other (3.4 ) (5.3 ) (3.7 ) Income Tax Expense $ 52.1 $ 84.8 $ 66.4 Effective Income Tax Rate 23.5 % 30.2 % 31.5 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2016 2015 (in millions) Deferred Tax Assets $ 2,753.0 $ 2,503.9 Deferred Tax Liabilities (14,637.4 ) (14,237.1 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) Property Related Temporary Differences $ (8,758.1 ) $ (8,533.3 ) Amounts Due from Customers for Future Federal Income Taxes (292.2 ) (263.5 ) Deferred State Income Taxes (976.6 ) (872.0 ) Securitized Assets (535.6 ) (633.2 ) Regulatory Assets (896.9 ) (873.6 ) Deferred Income Taxes on Other Comprehensive Loss 88.7 72.2 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Net Operating Loss Carryforward 101.2 39.6 Tax Credit Carryforward 45.1 85.0 Valuation Allowance (1.8 ) (130.0 ) All Other, Net 8.6 (9.8 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) APCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 413.5 $ 412.9 Deferred Tax Liabilities (3,085.8 ) (2,939.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) Property Related Temporary Differences $ (2,031.9 ) $ (1,866.0 ) Amounts Due from Customers for Future Federal Income Taxes (73.1 ) (68.2 ) Deferred State Income Taxes (319.3 ) (308.7 ) Regulatory Assets (159.9 ) (169.1 ) Securitized Assets (106.9 ) (114.8 ) Deferred Income Taxes on Other Comprehensive Loss 4.5 1.5 Tax Credit Carryforward 11.7 19.2 All Other, Net 2.6 (20.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) I&M December 31, 2016 2015 (in millions) Deferred Tax Assets $ 912.9 $ 837.4 Deferred Tax Liabilities (2,440.3 ) (2,198.9 ) Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) Property Related Temporary Differences $ (579.4 ) $ (521.6 ) Amounts Due from Customers for Future Federal Income Taxes (50.4 ) (42.7 ) Deferred State Income Taxes (158.7 ) (124.8 ) Deferred Income Taxes on Other Comprehensive Loss 8.8 9.0 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Regulatory Assets (81.0 ) (70.2 ) Net Operating Loss Carryforward 7.1 — All Other, Net (7.0 ) 3.4 Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) OPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 232.4 $ 162.4 Deferred Tax Liabilities (1,578.5 ) (1,545.6 ) Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) Property Related Temporary Differences $ (1,090.8 ) $ (1,022.8 ) Amounts Due from Customers for Future Federal Income Taxes (43.6 ) (44.6 ) Deferred State Income Taxes (34.6 ) (34.4 ) Regulatory Assets (174.1 ) (220.0 ) Deferred Income Taxes on Other Comprehensive Loss (1.6 ) (2.3 ) Deferred Fuel and Purchased Power (117.6 ) (117.4 ) All Other, Net 116.2 58.3 Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) PSO December 31, 2016 2015 (in millions) Deferred Tax Assets $ 153.8 $ 141.2 Deferred Tax Liabilities (1,212.6 ) (1,113.0 ) Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) Property Related Temporary Differences $ (927.3 ) $ (861.9 ) Amounts Due from Customers for Future Federal Income Taxes (3.2 ) (2.2 ) Deferred State Income Taxes (128.5 ) (117.0 ) Regulatory Assets (67.6 ) (54.3 ) Deferred Income Taxes on Other Comprehensive Loss (1.8 ) (2.3 ) Deferred Federal Income Taxes on Deferred State Income Taxes 50.6 46.6 Net Operating Loss Carryforward 16.5 7.1 Tax Credit Carryforward — 0.6 All Other, Net 2.5 11.6 Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) SWEPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 230.5 $ 194.7 Deferred Tax Liabilities (1,837.4 ) (1,594.5 ) Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) Property Related Temporary Differences $ (1,445.2 ) $ (1,275.1 ) Amounts Due from Customers for Future Federal Income Taxes (48.2 ) (47.8 ) Deferred State Income Taxes (175.1 ) (132.3 ) Regulatory Assets (40.7 ) (26.1 ) Deferred Income Taxes on Other Comprehensive Loss 5.1 5.0 Impairment Loss - Turk Plant 20.3 20.7 Net Operating Loss Carryforward 40.3 19.7 Tax Credit Carryforward 0.1 0.7 All Other, Net 36.5 35.4 Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. As of December 31, 2015 there was a valuation allowance of $130 million recorded against AEP’s deferred tax asset balance. AEP recorded changes in the valuation allowance in the second quarter of 2016 related to the reversal of a $56 million unrealized capital loss where AEP effectively settled a 2011 audit issue with the IRS. AEP also recorded changes in the third quarter of 2016 by reducing the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets held for sale and the filing of the 2015 federal income tax return. The sale of these assets held for sale are expected to result in a gain, the character of which will allow AEP to recognize the capital loss and allowed AEP to reverse substantially all of the remaining capital loss valuation allowance previously recorded. During the fourth quarter of 2016, AEP reversed $6 million of the valuation allowance associated with charitable contributions that expired at the end of the year. As of December 31, 2016 there was a valuation allowance of $2 million recorded against AEP’s deferred tax asset balance related to an unrealized capital loss carryforward. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine their tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. Net Income Tax Operating Loss Carryforward In 2016, AEP, I&M, PSO and SWEPCo recognized federal net income tax operating losses of $143 million , $20 million , $17 million and $37 million , respectively, which were driven primarily by bonus depreciation. As of December 31, 2016, AEP, I&M, PSO and SWEPCo had $50 million , $7 million , $6 million and $13 million , respectively, of unrealized federal net operating loss carryforward tax benefits. Management anticipates future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2036 . AEP, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2016 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036 Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2016 and 2015, AEP had $17 million and $59 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2016, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2032 through 2036 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. In the first quarter of 2017, AEP received the tax refund related to the U.K. Windfall Tax, including interest through the date of the refund. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2 The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties: Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9 Federal Tax Legislation The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. Additional legislation was passed by the state of Indiana reducing the corporate income tax rate from 6.5% in 2016 to 4.9% beginning after June 30, 2016 with the final reduction occurring in years beginning after June 30, 2021. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrants’ net income, cash flows, or financial condition. 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 income/franchise 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 in 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 the Registrants’ net income, cash flows or financial condition.
Ohio Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Income Tax Expense (Credit) The details of the Registrants’ income tax expense (credit) before discontinued operations as reported are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 AEP Years Ended December 31, 2015 2014 (in millions) Federal: Current $ 107.3 $ 22.8 Deferred 774.8 800.1 Total Federal 882.1 822.9 State and Local: Current 14.5 22.8 Deferred 23.0 56.9 Total State and Local 37.5 79.7 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 618.0 $ 2,052.3 $ 1,638.0 Discontinued Operations (Net of Income Tax of $0, $6.2 and $39 in 2016, 2015 and 2014, Respectively) 2.5 (283.7 ) (47.5 ) Income Tax Expense (Credit) Before Discontinued Operations (73.7 ) 919.6 902.6 Pretax Income $ 546.8 $ 2,688.2 $ 2,493.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 191.4 $ 940.9 $ 872.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 41.7 53.6 54.0 Investment Tax Credits, Net (12.3 ) (11.6 ) (12.8 ) State and Local Income Taxes, Net (20.7 ) 24.4 54.3 Removal Costs (39.8 ) (28.8 ) (23.9 ) AFUDC (44.8 ) (51.6 ) (41.8 ) Valuation Allowance (128.3 ) 17.2 (2.5 ) U.K. Windfall Tax (12.9 ) — — Tax Adjustments (43.9 ) (20.1 ) (10.1 ) Other (4.1 ) (4.4 ) 12.8 Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 919.6 $ 902.6 Effective Income Tax Rate (13.5 ) % 34.2 % 36.2 % APCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 369.1 $ 340.6 $ 215.4 Income Tax Expense 199.1 194.3 154.9 Pretax Income $ 568.2 $ 534.9 $ 370.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 198.9 $ 187.2 $ 129.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.3 19.8 23.5 Investment Tax Credits, Net (0.1 ) (0.3 ) (0.6 ) State and Local Income Taxes, Net 6.0 7.2 6.5 Removal Costs (12.0 ) (9.9 ) (6.8 ) AFUDC (6.1 ) (7.0 ) (3.8 ) Valuation Allowance (1.7 ) 1.7 (2.5 ) Other (5.2 ) (4.4 ) 9.0 Income Tax Expense $ 199.1 $ 194.3 $ 154.9 Effective Income Tax Rate 35.0 % 36.3 % 41.8 % I&M Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 239.9 $ 204.8 $ 155.6 Income Tax Expense 67.5 96.1 79.6 Pretax Income $ 307.4 $ 300.9 $ 235.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 107.6 $ 105.3 $ 82.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 6.7 9.5 12.9 Investment Tax Credits, Net (4.7 ) (3.3 ) (4.9 ) State and Local Income Taxes, Net 2.4 5.8 7.7 Removal Costs (21.3 ) (12.6 ) (11.3 ) AFUDC (7.3 ) (6.2 ) (10.0 ) Tax Adjustments (14.2 ) (4.2 ) 1.2 Other (1.7 ) 1.8 1.7 Income Tax Expense $ 67.5 $ 96.1 $ 79.6 Effective Income Tax Rate 22.0 % 31.9 % 33.8 % OPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 282.2 $ 232.7 $ 216.4 Income Tax Expense 143.8 126.5 132.2 Pretax Income $ 426.0 $ 359.2 $ 348.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 149.1 $ 125.7 $ 122.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.1 8.2 6.7 Investment Tax Credits, Net — (0.1 ) (0.2 ) State and Local Income Taxes, Net 3.8 0.7 8.8 Other (16.2 ) (8.0 ) (5.1 ) Income Tax Expense $ 143.8 $ 126.5 $ 132.2 Effective Income Tax Rate 33.8 % 35.2 % 37.9 % PSO Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 100.0 $ 92.5 $ 86.9 Income Tax Expense 54.4 51.3 50.6 Pretax Income $ 154.4 $ 143.8 $ 137.5 Income Taxes on Pretax Income at Statutory Rate (35%) $ 54.0 $ 50.3 $ 48.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.8 0.5 0.2 Investment Tax Credits, Net (1.4 ) (1.8 ) (0.8 ) State and Local Income Taxes, Net 4.2 5.1 4.8 AFUDC (2.2 ) (3.1 ) (1.1 ) Other (1.0 ) 0.3 (0.6 ) Income Tax Expense $ 54.4 $ 51.3 $ 50.6 Effective Income Tax Rate 35.2 % 35.7 % 36.8 % SWEPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 169.7 $ 196.0 $ 144.6 Income Tax Expense 52.1 84.8 66.4 Pretax Income $ 221.8 $ 280.8 $ 211.0 Income Taxes on Pretax Income at Statutory Rate (35%) $ 77.6 $ 98.3 $ 73.8 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.2 3.1 2.9 Depletion (5.5 ) (5.5 ) (4.1 ) Investment Tax Credits, Net (1.2 ) (1.4 ) (1.4 ) State and Local Income Taxes, Net (14.7 ) 4.8 3.1 AFUDC (3.9 ) (9.2 ) (4.2 ) Other (3.4 ) (5.3 ) (3.7 ) Income Tax Expense $ 52.1 $ 84.8 $ 66.4 Effective Income Tax Rate 23.5 % 30.2 % 31.5 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2016 2015 (in millions) Deferred Tax Assets $ 2,753.0 $ 2,503.9 Deferred Tax Liabilities (14,637.4 ) (14,237.1 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) Property Related Temporary Differences $ (8,758.1 ) $ (8,533.3 ) Amounts Due from Customers for Future Federal Income Taxes (292.2 ) (263.5 ) Deferred State Income Taxes (976.6 ) (872.0 ) Securitized Assets (535.6 ) (633.2 ) Regulatory Assets (896.9 ) (873.6 ) Deferred Income Taxes on Other Comprehensive Loss 88.7 72.2 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Net Operating Loss Carryforward 101.2 39.6 Tax Credit Carryforward 45.1 85.0 Valuation Allowance (1.8 ) (130.0 ) All Other, Net 8.6 (9.8 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) APCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 413.5 $ 412.9 Deferred Tax Liabilities (3,085.8 ) (2,939.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) Property Related Temporary Differences $ (2,031.9 ) $ (1,866.0 ) Amounts Due from Customers for Future Federal Income Taxes (73.1 ) (68.2 ) Deferred State Income Taxes (319.3 ) (308.7 ) Regulatory Assets (159.9 ) (169.1 ) Securitized Assets (106.9 ) (114.8 ) Deferred Income Taxes on Other Comprehensive Loss 4.5 1.5 Tax Credit Carryforward 11.7 19.2 All Other, Net 2.6 (20.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) I&M December 31, 2016 2015 (in millions) Deferred Tax Assets $ 912.9 $ 837.4 Deferred Tax Liabilities (2,440.3 ) (2,198.9 ) Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) Property Related Temporary Differences $ (579.4 ) $ (521.6 ) Amounts Due from Customers for Future Federal Income Taxes (50.4 ) (42.7 ) Deferred State Income Taxes (158.7 ) (124.8 ) Deferred Income Taxes on Other Comprehensive Loss 8.8 9.0 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Regulatory Assets (81.0 ) (70.2 ) Net Operating Loss Carryforward 7.1 — All Other, Net (7.0 ) 3.4 Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) OPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 232.4 $ 162.4 Deferred Tax Liabilities (1,578.5 ) (1,545.6 ) Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) Property Related Temporary Differences $ (1,090.8 ) $ (1,022.8 ) Amounts Due from Customers for Future Federal Income Taxes (43.6 ) (44.6 ) Deferred State Income Taxes (34.6 ) (34.4 ) Regulatory Assets (174.1 ) (220.0 ) Deferred Income Taxes on Other Comprehensive Loss (1.6 ) (2.3 ) Deferred Fuel and Purchased Power (117.6 ) (117.4 ) All Other, Net 116.2 58.3 Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) PSO December 31, 2016 2015 (in millions) Deferred Tax Assets $ 153.8 $ 141.2 Deferred Tax Liabilities (1,212.6 ) (1,113.0 ) Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) Property Related Temporary Differences $ (927.3 ) $ (861.9 ) Amounts Due from Customers for Future Federal Income Taxes (3.2 ) (2.2 ) Deferred State Income Taxes (128.5 ) (117.0 ) Regulatory Assets (67.6 ) (54.3 ) Deferred Income Taxes on Other Comprehensive Loss (1.8 ) (2.3 ) Deferred Federal Income Taxes on Deferred State Income Taxes 50.6 46.6 Net Operating Loss Carryforward 16.5 7.1 Tax Credit Carryforward — 0.6 All Other, Net 2.5 11.6 Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) SWEPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 230.5 $ 194.7 Deferred Tax Liabilities (1,837.4 ) (1,594.5 ) Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) Property Related Temporary Differences $ (1,445.2 ) $ (1,275.1 ) Amounts Due from Customers for Future Federal Income Taxes (48.2 ) (47.8 ) Deferred State Income Taxes (175.1 ) (132.3 ) Regulatory Assets (40.7 ) (26.1 ) Deferred Income Taxes on Other Comprehensive Loss 5.1 5.0 Impairment Loss - Turk Plant 20.3 20.7 Net Operating Loss Carryforward 40.3 19.7 Tax Credit Carryforward 0.1 0.7 All Other, Net 36.5 35.4 Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. As of December 31, 2015 there was a valuation allowance of $130 million recorded against AEP’s deferred tax asset balance. AEP recorded changes in the valuation allowance in the second quarter of 2016 related to the reversal of a $56 million unrealized capital loss where AEP effectively settled a 2011 audit issue with the IRS. AEP also recorded changes in the third quarter of 2016 by reducing the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets held for sale and the filing of the 2015 federal income tax return. The sale of these assets held for sale are expected to result in a gain, the character of which will allow AEP to recognize the capital loss and allowed AEP to reverse substantially all of the remaining capital loss valuation allowance previously recorded. During the fourth quarter of 2016, AEP reversed $6 million of the valuation allowance associated with charitable contributions that expired at the end of the year. As of December 31, 2016 there was a valuation allowance of $2 million recorded against AEP’s deferred tax asset balance related to an unrealized capital loss carryforward. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine their tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. Net Income Tax Operating Loss Carryforward In 2016, AEP, I&M, PSO and SWEPCo recognized federal net income tax operating losses of $143 million , $20 million , $17 million and $37 million , respectively, which were driven primarily by bonus depreciation. As of December 31, 2016, AEP, I&M, PSO and SWEPCo had $50 million , $7 million , $6 million and $13 million , respectively, of unrealized federal net operating loss carryforward tax benefits. Management anticipates future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2036 . AEP, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2016 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036 Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2016 and 2015, AEP had $17 million and $59 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2016, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2032 through 2036 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. In the first quarter of 2017, AEP received the tax refund related to the U.K. Windfall Tax, including interest through the date of the refund. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2 The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties: Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9 Federal Tax Legislation The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. Additional legislation was passed by the state of Indiana reducing the corporate income tax rate from 6.5% in 2016 to 4.9% beginning after June 30, 2016 with the final reduction occurring in years beginning after June 30, 2021. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrants’ net income, cash flows, or financial condition. 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 income/franchise 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 in 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 the Registrants’ net income, cash flows or financial condition.
Public Service Co Of Oklahoma [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Income Tax Expense (Credit) The details of the Registrants’ income tax expense (credit) before discontinued operations as reported are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 AEP Years Ended December 31, 2015 2014 (in millions) Federal: Current $ 107.3 $ 22.8 Deferred 774.8 800.1 Total Federal 882.1 822.9 State and Local: Current 14.5 22.8 Deferred 23.0 56.9 Total State and Local 37.5 79.7 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 618.0 $ 2,052.3 $ 1,638.0 Discontinued Operations (Net of Income Tax of $0, $6.2 and $39 in 2016, 2015 and 2014, Respectively) 2.5 (283.7 ) (47.5 ) Income Tax Expense (Credit) Before Discontinued Operations (73.7 ) 919.6 902.6 Pretax Income $ 546.8 $ 2,688.2 $ 2,493.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 191.4 $ 940.9 $ 872.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 41.7 53.6 54.0 Investment Tax Credits, Net (12.3 ) (11.6 ) (12.8 ) State and Local Income Taxes, Net (20.7 ) 24.4 54.3 Removal Costs (39.8 ) (28.8 ) (23.9 ) AFUDC (44.8 ) (51.6 ) (41.8 ) Valuation Allowance (128.3 ) 17.2 (2.5 ) U.K. Windfall Tax (12.9 ) — — Tax Adjustments (43.9 ) (20.1 ) (10.1 ) Other (4.1 ) (4.4 ) 12.8 Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 919.6 $ 902.6 Effective Income Tax Rate (13.5 ) % 34.2 % 36.2 % APCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 369.1 $ 340.6 $ 215.4 Income Tax Expense 199.1 194.3 154.9 Pretax Income $ 568.2 $ 534.9 $ 370.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 198.9 $ 187.2 $ 129.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.3 19.8 23.5 Investment Tax Credits, Net (0.1 ) (0.3 ) (0.6 ) State and Local Income Taxes, Net 6.0 7.2 6.5 Removal Costs (12.0 ) (9.9 ) (6.8 ) AFUDC (6.1 ) (7.0 ) (3.8 ) Valuation Allowance (1.7 ) 1.7 (2.5 ) Other (5.2 ) (4.4 ) 9.0 Income Tax Expense $ 199.1 $ 194.3 $ 154.9 Effective Income Tax Rate 35.0 % 36.3 % 41.8 % I&M Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 239.9 $ 204.8 $ 155.6 Income Tax Expense 67.5 96.1 79.6 Pretax Income $ 307.4 $ 300.9 $ 235.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 107.6 $ 105.3 $ 82.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 6.7 9.5 12.9 Investment Tax Credits, Net (4.7 ) (3.3 ) (4.9 ) State and Local Income Taxes, Net 2.4 5.8 7.7 Removal Costs (21.3 ) (12.6 ) (11.3 ) AFUDC (7.3 ) (6.2 ) (10.0 ) Tax Adjustments (14.2 ) (4.2 ) 1.2 Other (1.7 ) 1.8 1.7 Income Tax Expense $ 67.5 $ 96.1 $ 79.6 Effective Income Tax Rate 22.0 % 31.9 % 33.8 % OPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 282.2 $ 232.7 $ 216.4 Income Tax Expense 143.8 126.5 132.2 Pretax Income $ 426.0 $ 359.2 $ 348.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 149.1 $ 125.7 $ 122.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.1 8.2 6.7 Investment Tax Credits, Net — (0.1 ) (0.2 ) State and Local Income Taxes, Net 3.8 0.7 8.8 Other (16.2 ) (8.0 ) (5.1 ) Income Tax Expense $ 143.8 $ 126.5 $ 132.2 Effective Income Tax Rate 33.8 % 35.2 % 37.9 % PSO Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 100.0 $ 92.5 $ 86.9 Income Tax Expense 54.4 51.3 50.6 Pretax Income $ 154.4 $ 143.8 $ 137.5 Income Taxes on Pretax Income at Statutory Rate (35%) $ 54.0 $ 50.3 $ 48.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.8 0.5 0.2 Investment Tax Credits, Net (1.4 ) (1.8 ) (0.8 ) State and Local Income Taxes, Net 4.2 5.1 4.8 AFUDC (2.2 ) (3.1 ) (1.1 ) Other (1.0 ) 0.3 (0.6 ) Income Tax Expense $ 54.4 $ 51.3 $ 50.6 Effective Income Tax Rate 35.2 % 35.7 % 36.8 % SWEPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 169.7 $ 196.0 $ 144.6 Income Tax Expense 52.1 84.8 66.4 Pretax Income $ 221.8 $ 280.8 $ 211.0 Income Taxes on Pretax Income at Statutory Rate (35%) $ 77.6 $ 98.3 $ 73.8 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.2 3.1 2.9 Depletion (5.5 ) (5.5 ) (4.1 ) Investment Tax Credits, Net (1.2 ) (1.4 ) (1.4 ) State and Local Income Taxes, Net (14.7 ) 4.8 3.1 AFUDC (3.9 ) (9.2 ) (4.2 ) Other (3.4 ) (5.3 ) (3.7 ) Income Tax Expense $ 52.1 $ 84.8 $ 66.4 Effective Income Tax Rate 23.5 % 30.2 % 31.5 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2016 2015 (in millions) Deferred Tax Assets $ 2,753.0 $ 2,503.9 Deferred Tax Liabilities (14,637.4 ) (14,237.1 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) Property Related Temporary Differences $ (8,758.1 ) $ (8,533.3 ) Amounts Due from Customers for Future Federal Income Taxes (292.2 ) (263.5 ) Deferred State Income Taxes (976.6 ) (872.0 ) Securitized Assets (535.6 ) (633.2 ) Regulatory Assets (896.9 ) (873.6 ) Deferred Income Taxes on Other Comprehensive Loss 88.7 72.2 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Net Operating Loss Carryforward 101.2 39.6 Tax Credit Carryforward 45.1 85.0 Valuation Allowance (1.8 ) (130.0 ) All Other, Net 8.6 (9.8 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) APCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 413.5 $ 412.9 Deferred Tax Liabilities (3,085.8 ) (2,939.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) Property Related Temporary Differences $ (2,031.9 ) $ (1,866.0 ) Amounts Due from Customers for Future Federal Income Taxes (73.1 ) (68.2 ) Deferred State Income Taxes (319.3 ) (308.7 ) Regulatory Assets (159.9 ) (169.1 ) Securitized Assets (106.9 ) (114.8 ) Deferred Income Taxes on Other Comprehensive Loss 4.5 1.5 Tax Credit Carryforward 11.7 19.2 All Other, Net 2.6 (20.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) I&M December 31, 2016 2015 (in millions) Deferred Tax Assets $ 912.9 $ 837.4 Deferred Tax Liabilities (2,440.3 ) (2,198.9 ) Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) Property Related Temporary Differences $ (579.4 ) $ (521.6 ) Amounts Due from Customers for Future Federal Income Taxes (50.4 ) (42.7 ) Deferred State Income Taxes (158.7 ) (124.8 ) Deferred Income Taxes on Other Comprehensive Loss 8.8 9.0 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Regulatory Assets (81.0 ) (70.2 ) Net Operating Loss Carryforward 7.1 — All Other, Net (7.0 ) 3.4 Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) OPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 232.4 $ 162.4 Deferred Tax Liabilities (1,578.5 ) (1,545.6 ) Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) Property Related Temporary Differences $ (1,090.8 ) $ (1,022.8 ) Amounts Due from Customers for Future Federal Income Taxes (43.6 ) (44.6 ) Deferred State Income Taxes (34.6 ) (34.4 ) Regulatory Assets (174.1 ) (220.0 ) Deferred Income Taxes on Other Comprehensive Loss (1.6 ) (2.3 ) Deferred Fuel and Purchased Power (117.6 ) (117.4 ) All Other, Net 116.2 58.3 Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) PSO December 31, 2016 2015 (in millions) Deferred Tax Assets $ 153.8 $ 141.2 Deferred Tax Liabilities (1,212.6 ) (1,113.0 ) Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) Property Related Temporary Differences $ (927.3 ) $ (861.9 ) Amounts Due from Customers for Future Federal Income Taxes (3.2 ) (2.2 ) Deferred State Income Taxes (128.5 ) (117.0 ) Regulatory Assets (67.6 ) (54.3 ) Deferred Income Taxes on Other Comprehensive Loss (1.8 ) (2.3 ) Deferred Federal Income Taxes on Deferred State Income Taxes 50.6 46.6 Net Operating Loss Carryforward 16.5 7.1 Tax Credit Carryforward — 0.6 All Other, Net 2.5 11.6 Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) SWEPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 230.5 $ 194.7 Deferred Tax Liabilities (1,837.4 ) (1,594.5 ) Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) Property Related Temporary Differences $ (1,445.2 ) $ (1,275.1 ) Amounts Due from Customers for Future Federal Income Taxes (48.2 ) (47.8 ) Deferred State Income Taxes (175.1 ) (132.3 ) Regulatory Assets (40.7 ) (26.1 ) Deferred Income Taxes on Other Comprehensive Loss 5.1 5.0 Impairment Loss - Turk Plant 20.3 20.7 Net Operating Loss Carryforward 40.3 19.7 Tax Credit Carryforward 0.1 0.7 All Other, Net 36.5 35.4 Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. As of December 31, 2015 there was a valuation allowance of $130 million recorded against AEP’s deferred tax asset balance. AEP recorded changes in the valuation allowance in the second quarter of 2016 related to the reversal of a $56 million unrealized capital loss where AEP effectively settled a 2011 audit issue with the IRS. AEP also recorded changes in the third quarter of 2016 by reducing the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets held for sale and the filing of the 2015 federal income tax return. The sale of these assets held for sale are expected to result in a gain, the character of which will allow AEP to recognize the capital loss and allowed AEP to reverse substantially all of the remaining capital loss valuation allowance previously recorded. During the fourth quarter of 2016, AEP reversed $6 million of the valuation allowance associated with charitable contributions that expired at the end of the year. As of December 31, 2016 there was a valuation allowance of $2 million recorded against AEP’s deferred tax asset balance related to an unrealized capital loss carryforward. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine their tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. Net Income Tax Operating Loss Carryforward In 2016, AEP, I&M, PSO and SWEPCo recognized federal net income tax operating losses of $143 million , $20 million , $17 million and $37 million , respectively, which were driven primarily by bonus depreciation. As of December 31, 2016, AEP, I&M, PSO and SWEPCo had $50 million , $7 million , $6 million and $13 million , respectively, of unrealized federal net operating loss carryforward tax benefits. Management anticipates future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2036 . AEP, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2016 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036 Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2016 and 2015, AEP had $17 million and $59 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2016, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2032 through 2036 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. In the first quarter of 2017, AEP received the tax refund related to the U.K. Windfall Tax, including interest through the date of the refund. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2 The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties: Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9 Federal Tax Legislation The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. Additional legislation was passed by the state of Indiana reducing the corporate income tax rate from 6.5% in 2016 to 4.9% beginning after June 30, 2016 with the final reduction occurring in years beginning after June 30, 2021. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrants’ net income, cash flows, or financial condition. 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 income/franchise 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 in 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 the Registrants’ net income, cash flows or financial condition.
Southwestern Electric Power Co [Member]
Income Taxes	INCOME TAXES The disclosures in this note apply to all Registrants unless indicated otherwise. Income Tax Expense (Credit) The details of the Registrants’ income tax expense (credit) before discontinued operations as reported are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 AEP Years Ended December 31, 2015 2014 (in millions) Federal: Current $ 107.3 $ 22.8 Deferred 774.8 800.1 Total Federal 882.1 822.9 State and Local: Current 14.5 22.8 Deferred 23.0 56.9 Total State and Local 37.5 79.7 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 The following is a reconciliation for each Registrant of the difference between the amounts of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported: AEP Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 618.0 $ 2,052.3 $ 1,638.0 Discontinued Operations (Net of Income Tax of $0, $6.2 and $39 in 2016, 2015 and 2014, Respectively) 2.5 (283.7 ) (47.5 ) Income Tax Expense (Credit) Before Discontinued Operations (73.7 ) 919.6 902.6 Pretax Income $ 546.8 $ 2,688.2 $ 2,493.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 191.4 $ 940.9 $ 872.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 41.7 53.6 54.0 Investment Tax Credits, Net (12.3 ) (11.6 ) (12.8 ) State and Local Income Taxes, Net (20.7 ) 24.4 54.3 Removal Costs (39.8 ) (28.8 ) (23.9 ) AFUDC (44.8 ) (51.6 ) (41.8 ) Valuation Allowance (128.3 ) 17.2 (2.5 ) U.K. Windfall Tax (12.9 ) — — Tax Adjustments (43.9 ) (20.1 ) (10.1 ) Other (4.1 ) (4.4 ) 12.8 Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 919.6 $ 902.6 Effective Income Tax Rate (13.5 ) % 34.2 % 36.2 % APCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 369.1 $ 340.6 $ 215.4 Income Tax Expense 199.1 194.3 154.9 Pretax Income $ 568.2 $ 534.9 $ 370.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 198.9 $ 187.2 $ 129.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.3 19.8 23.5 Investment Tax Credits, Net (0.1 ) (0.3 ) (0.6 ) State and Local Income Taxes, Net 6.0 7.2 6.5 Removal Costs (12.0 ) (9.9 ) (6.8 ) AFUDC (6.1 ) (7.0 ) (3.8 ) Valuation Allowance (1.7 ) 1.7 (2.5 ) Other (5.2 ) (4.4 ) 9.0 Income Tax Expense $ 199.1 $ 194.3 $ 154.9 Effective Income Tax Rate 35.0 % 36.3 % 41.8 % I&M Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 239.9 $ 204.8 $ 155.6 Income Tax Expense 67.5 96.1 79.6 Pretax Income $ 307.4 $ 300.9 $ 235.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 107.6 $ 105.3 $ 82.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 6.7 9.5 12.9 Investment Tax Credits, Net (4.7 ) (3.3 ) (4.9 ) State and Local Income Taxes, Net 2.4 5.8 7.7 Removal Costs (21.3 ) (12.6 ) (11.3 ) AFUDC (7.3 ) (6.2 ) (10.0 ) Tax Adjustments (14.2 ) (4.2 ) 1.2 Other (1.7 ) 1.8 1.7 Income Tax Expense $ 67.5 $ 96.1 $ 79.6 Effective Income Tax Rate 22.0 % 31.9 % 33.8 % OPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 282.2 $ 232.7 $ 216.4 Income Tax Expense 143.8 126.5 132.2 Pretax Income $ 426.0 $ 359.2 $ 348.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 149.1 $ 125.7 $ 122.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.1 8.2 6.7 Investment Tax Credits, Net — (0.1 ) (0.2 ) State and Local Income Taxes, Net 3.8 0.7 8.8 Other (16.2 ) (8.0 ) (5.1 ) Income Tax Expense $ 143.8 $ 126.5 $ 132.2 Effective Income Tax Rate 33.8 % 35.2 % 37.9 % PSO Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 100.0 $ 92.5 $ 86.9 Income Tax Expense 54.4 51.3 50.6 Pretax Income $ 154.4 $ 143.8 $ 137.5 Income Taxes on Pretax Income at Statutory Rate (35%) $ 54.0 $ 50.3 $ 48.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.8 0.5 0.2 Investment Tax Credits, Net (1.4 ) (1.8 ) (0.8 ) State and Local Income Taxes, Net 4.2 5.1 4.8 AFUDC (2.2 ) (3.1 ) (1.1 ) Other (1.0 ) 0.3 (0.6 ) Income Tax Expense $ 54.4 $ 51.3 $ 50.6 Effective Income Tax Rate 35.2 % 35.7 % 36.8 % SWEPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 169.7 $ 196.0 $ 144.6 Income Tax Expense 52.1 84.8 66.4 Pretax Income $ 221.8 $ 280.8 $ 211.0 Income Taxes on Pretax Income at Statutory Rate (35%) $ 77.6 $ 98.3 $ 73.8 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.2 3.1 2.9 Depletion (5.5 ) (5.5 ) (4.1 ) Investment Tax Credits, Net (1.2 ) (1.4 ) (1.4 ) State and Local Income Taxes, Net (14.7 ) 4.8 3.1 AFUDC (3.9 ) (9.2 ) (4.2 ) Other (3.4 ) (5.3 ) (3.7 ) Income Tax Expense $ 52.1 $ 84.8 $ 66.4 Effective Income Tax Rate 23.5 % 30.2 % 31.5 % Net Deferred Tax Liability The following tables show elements of the net deferred tax liability and significant temporary differences for each Registrant: AEP December 31, 2016 2015 (in millions) Deferred Tax Assets $ 2,753.0 $ 2,503.9 Deferred Tax Liabilities (14,637.4 ) (14,237.1 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) Property Related Temporary Differences $ (8,758.1 ) $ (8,533.3 ) Amounts Due from Customers for Future Federal Income Taxes (292.2 ) (263.5 ) Deferred State Income Taxes (976.6 ) (872.0 ) Securitized Assets (535.6 ) (633.2 ) Regulatory Assets (896.9 ) (873.6 ) Deferred Income Taxes on Other Comprehensive Loss 88.7 72.2 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Net Operating Loss Carryforward 101.2 39.6 Tax Credit Carryforward 45.1 85.0 Valuation Allowance (1.8 ) (130.0 ) All Other, Net 8.6 (9.8 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) APCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 413.5 $ 412.9 Deferred Tax Liabilities (3,085.8 ) (2,939.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) Property Related Temporary Differences $ (2,031.9 ) $ (1,866.0 ) Amounts Due from Customers for Future Federal Income Taxes (73.1 ) (68.2 ) Deferred State Income Taxes (319.3 ) (308.7 ) Regulatory Assets (159.9 ) (169.1 ) Securitized Assets (106.9 ) (114.8 ) Deferred Income Taxes on Other Comprehensive Loss 4.5 1.5 Tax Credit Carryforward 11.7 19.2 All Other, Net 2.6 (20.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) I&M December 31, 2016 2015 (in millions) Deferred Tax Assets $ 912.9 $ 837.4 Deferred Tax Liabilities (2,440.3 ) (2,198.9 ) Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) Property Related Temporary Differences $ (579.4 ) $ (521.6 ) Amounts Due from Customers for Future Federal Income Taxes (50.4 ) (42.7 ) Deferred State Income Taxes (158.7 ) (124.8 ) Deferred Income Taxes on Other Comprehensive Loss 8.8 9.0 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Regulatory Assets (81.0 ) (70.2 ) Net Operating Loss Carryforward 7.1 — All Other, Net (7.0 ) 3.4 Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) OPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 232.4 $ 162.4 Deferred Tax Liabilities (1,578.5 ) (1,545.6 ) Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) Property Related Temporary Differences $ (1,090.8 ) $ (1,022.8 ) Amounts Due from Customers for Future Federal Income Taxes (43.6 ) (44.6 ) Deferred State Income Taxes (34.6 ) (34.4 ) Regulatory Assets (174.1 ) (220.0 ) Deferred Income Taxes on Other Comprehensive Loss (1.6 ) (2.3 ) Deferred Fuel and Purchased Power (117.6 ) (117.4 ) All Other, Net 116.2 58.3 Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) PSO December 31, 2016 2015 (in millions) Deferred Tax Assets $ 153.8 $ 141.2 Deferred Tax Liabilities (1,212.6 ) (1,113.0 ) Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) Property Related Temporary Differences $ (927.3 ) $ (861.9 ) Amounts Due from Customers for Future Federal Income Taxes (3.2 ) (2.2 ) Deferred State Income Taxes (128.5 ) (117.0 ) Regulatory Assets (67.6 ) (54.3 ) Deferred Income Taxes on Other Comprehensive Loss (1.8 ) (2.3 ) Deferred Federal Income Taxes on Deferred State Income Taxes 50.6 46.6 Net Operating Loss Carryforward 16.5 7.1 Tax Credit Carryforward — 0.6 All Other, Net 2.5 11.6 Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) SWEPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 230.5 $ 194.7 Deferred Tax Liabilities (1,837.4 ) (1,594.5 ) Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) Property Related Temporary Differences $ (1,445.2 ) $ (1,275.1 ) Amounts Due from Customers for Future Federal Income Taxes (48.2 ) (47.8 ) Deferred State Income Taxes (175.1 ) (132.3 ) Regulatory Assets (40.7 ) (26.1 ) Deferred Income Taxes on Other Comprehensive Loss 5.1 5.0 Impairment Loss - Turk Plant 20.3 20.7 Net Operating Loss Carryforward 40.3 19.7 Tax Credit Carryforward 0.1 0.7 All Other, Net 36.5 35.4 Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group. Valuation Allowance AEP assesses the available positive and negative evidence to estimate whether sufficient future taxable income of the appropriate tax character will be generated to realize the benefits of existing deferred tax assets. When the evaluation of the evidence indicates that AEP will not be able to realize the benefits of existing deferred tax assets, a valuation allowance is recorded to reduce existing deferred tax assets to the net realizable amount. Objective negative evidence evaluated includes whether AEP has a history of recognizing income of the character which can be offset by loss carryforwards. Other objective negative evidence evaluated is the impact recently enacted federal tax legislation will have on future taxable income and on AEP’s ability to benefit from the carryforward of charitable contribution deductions. On the basis of this evaluation, AEP recorded a valuation allowance of $17 million in the fourth quarter of 2015 related to the expected expiration of charitable contribution carryforward deductions and realized capital losses. In the fourth quarter of 2015 AEP also reversed a valuation allowance originally recorded in the third quarter of 2015 of $156 million attributable to the unrealized capital loss associated with the excess tax basis of the stock over the book value of AEP’s investment in the operations of AEPRO. With the sale of AEPRO in the fourth quarter of 2015, AEP recorded a valuation allowance of $48 million attributable to realized capital losses from the sale. As of December 31, 2015 there was a valuation allowance of $130 million recorded against AEP’s deferred tax asset balance. AEP recorded changes in the valuation allowance in the second quarter of 2016 related to the reversal of a $56 million unrealized capital loss where AEP effectively settled a 2011 audit issue with the IRS. AEP also recorded changes in the third quarter of 2016 by reducing the capital loss valuation allowance by $66 million to reflect the impact of the reclassification of certain assets held for sale and the filing of the 2015 federal income tax return. The sale of these assets held for sale are expected to result in a gain, the character of which will allow AEP to recognize the capital loss and allowed AEP to reverse substantially all of the remaining capital loss valuation allowance previously recorded. During the fourth quarter of 2016, AEP reversed $6 million of the valuation allowance associated with charitable contributions that expired at the end of the year. As of December 31, 2016 there was a valuation allowance of $2 million recorded against AEP’s deferred tax asset balance related to an unrealized capital loss carryforward. Federal and State Income Tax Audit Status AEP and subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. AEP and subsidiaries received a Revenue Agents Report in April 2016, completing the 2011 through 2013 audit cycle indicating an agreed upon audit. The 2011 through 2013 audit was submitted to the Congressional Joint Committee on Taxation for approval. The Joint Committee referred the audit back to the IRS exam team for further consideration. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrants accrue interest on these uncertain tax positions. Management is not aware of any issues for open tax years that upon final resolution are expected to materially impact net income. AEP and subsidiaries file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine their tax returns. AEP and subsidiaries are currently under examination in several state and local jurisdictions. However, it is possible that previously filed tax returns have positions that may be challenged by these tax authorities. Management believes that adequate provisions for income taxes have been made for potential liabilities resulting from such challenges and that the ultimate resolution of these audits will not materially impact net income. The Registrants are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009. Net Income Tax Operating Loss Carryforward In 2016, AEP, I&M, PSO and SWEPCo recognized federal net income tax operating losses of $143 million , $20 million , $17 million and $37 million , respectively, which were driven primarily by bonus depreciation. As of December 31, 2016, AEP, I&M, PSO and SWEPCo had $50 million , $7 million , $6 million and $13 million , respectively, of unrealized federal net operating loss carryforward tax benefits. Management anticipates future taxable income will be sufficient to realize the remaining net income tax operating loss tax benefits before the federal carryforward expires after 2036 . AEP, PSO and SWEPCo also have state net income tax operating loss carryforwards as of December 31, 2016 as indicated in the table below: Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036 Management anticipates future taxable income will be sufficient to realize the remaining state net income tax operating loss tax benefits before the state carryforward expires for each state. As of December 31, 2013, AEP had $121 million of uncertain tax positions netted against the federal net income tax operating loss carryforward tax benefits. Due to the utilization of the net operating loss carryforward in 2014, $69 million is presented as a non-current uncertain tax position. As of December 31, 2016 and 2015, AEP had $17 million and $59 million , respectively, of uncertain tax positions netted against deferred tax liabilities. Tax Credit Carryforward Federal and state net income tax operating losses sustained in 2012, 2011 and 2009 along with lower federal and state taxable income in 2010 resulted in unused federal and state income tax credits. As of December 31, 2016, the Registrants have federal tax credit carryforwards and AEP and PSO have state tax credit carryforwards as indicated in the table below. If these credits are not utilized, federal general business tax credits will expire in the years 2032 through 2036 . Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — — The Registrants anticipate future federal taxable income will be sufficient to realize the tax benefits of the federal tax credits before they expire unused. In November 2014, APCo received an order from the Virginia SCC for its 2014 Virginia Biennial Base Rate Case (see Note 4 ). As a result of the final determination pertaining to the ability to realize future tax benefits for certain state net income tax operating loss and credit carryforwards, management determined that APCo is subject to the Virginia Minimum Tax on electric suppliers and the Virginia State Income Tax is no longer applicable. As a result, management derecognized the related state income tax benefits, which had been subject to valuation allowances. Uncertain Tax Positions In May 2013, the U.S. Supreme Court decided that the U.K. Windfall Tax imposed upon U.K. electric companies privatized between 1984 and 1996 is a creditable tax for U.S. federal income tax purposes. AEP filed protective claims asserting the creditability of the tax, dependent upon the outcome of the case. As a result of the favorable U.S. Supreme Court decision, AEP recognized a tax benefit of $80 million , plus $43 million of pretax interest income in the second quarter of 2013. In the first quarter of 2017, AEP received the tax refund related to the U.K. Windfall Tax, including interest through the date of the refund. The Registrants recognize interest accruals related to uncertain tax positions in interest income or expense as applicable and penalties in Other Operation expense in accordance with the accounting guidance for “Income Taxes.” The following tables show amounts reported for interest expense, interest income and reversal of prior period interest expense: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2 The following table shows balances for amounts accrued for the receipt of interest and the payment of interest and penalties: Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4 The reconciliations of the beginning and ending amounts of unrecognized tax benefits are as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Management believes that there will be no significant net increase or decrease in unrecognized benefits within 12 months of the reporting date. The total amount of unrecognized tax benefits that, if recognized, would affect the effective tax rate for each Registrant was as follows: Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9 Federal Tax Legislation The Tax Increase Prevention Act of 2014 (the 2014 Act) was enacted in December 2014. Included in the 2014 Act was a one-year extension of the 50% bonus depreciation. The 2014 Act also retroactively extended the life of research and development, employment and several energy tax credits, which expired at the end of 2013. The enacted provisions did not materially impact the Registrants’ net income or financial condition but did have a favorable impact on cash flows in 2015. The Protecting Americans from Tax Hikes Act of 2015 (PATH) included an extension of the 50% bonus depreciation for three years through 2017, phasing down to 40% in 2018 and 30% in 2019. PATH also provided for the extension of research and development, employment and several energy tax credits for 2015. PATH also includes provisions to extend the wind energy production tax credit through 2016 with a three-year phase-out (2017-2019), and to extend the 30% temporary solar investment tax credit for three years through 2019 and with a two-year phase-out (2020-2021). PATH also provided for a permanent extension of the Research and Development tax credit. The enacted provisions did not materially impact the Registrants’ net income or financial condition but will have a favorable impact on future cash flows. Federal Tax Regulations In 2013, the U.S. Treasury Department issued final and re-proposed regulations regarding the deduction and capitalization of expenditures related to tangible property, effective for the tax years beginning in 2014. In addition, the IRS issued Revenue Procedures under the Industry Issue Resolutions program that provides specific guidance for the implementation of the regulations for the electric utility industry. These final regulations did not materially impact the Registrants’ net income, cash flows or financial condition. State Tax Legislation Legislation was passed by the state of Indiana in May 2011 enacting a phased reduction in corporate income tax rate from 8.5% to 6.5% . The 8.5% Indiana corporate income tax rate will be reduced 0.5% each year beginning after June 30, 2012, with the final reduction occurring in years beginning after June 30, 2015. Additional legislation was passed by the state of Indiana reducing the corporate income tax rate from 6.5% in 2016 to 4.9% beginning after June 30, 2016 with the final reduction occurring in years beginning after June 30, 2021. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. During the third quarter of 2013, it was determined that the state of West Virginia had achieved certain minimum levels of shortfall reserve funds. As a result, the West Virginia corporate income tax rate was reduced from 7% to 6.5% in 2014. The legislation did not materially impact the Registrants’ net income, cash flows or financial condition. House Bill 32 was passed by the state of Texas in June 2015, permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrants’ net income, cash flows, or financial condition. 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 income/franchise 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 in 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 the Registrants’ net income, cash flows or financial condition.

Leases

Leases	12 Months Ended
	Dec. 31, 2016
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 15 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following tables show the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Future minimum lease payments consisted of the following as of December 31, 2016 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9 Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of December 31, 2016 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2016 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2017 $ 147.8 $ 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 Later Years 147.2 73.6 Total Future Minimum Lease Payments $ 886.2 $ 443.1 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2016 . These obligations are included in the future minimum lease payments schedule earlier in this note. Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 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)” section of Note 7 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2026. As of December 31, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $85 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2016 , AEP’s boat and barge lease guarantee liability was $13 million , of which $2 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. During 2016, the lease term came to an end and the lease obligation was paid in full. As of December 31, 2015, these capital lease assets were included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations were included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $8 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2016 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2017 $ 5.8 2018 2.4 Total Future Minimum Lease Payments $ 8.2
Appalachian Power Co [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 15 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following tables show the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Future minimum lease payments consisted of the following as of December 31, 2016 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9 Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of December 31, 2016 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2016 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2017 $ 147.8 $ 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 Later Years 147.2 73.6 Total Future Minimum Lease Payments $ 886.2 $ 443.1 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2016 . These obligations are included in the future minimum lease payments schedule earlier in this note. Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 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)” section of Note 7 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2026. As of December 31, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $85 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2016 , AEP’s boat and barge lease guarantee liability was $13 million , of which $2 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. During 2016, the lease term came to an end and the lease obligation was paid in full. As of December 31, 2015, these capital lease assets were included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations were included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $8 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2016 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2017 $ 5.8 2018 2.4 Total Future Minimum Lease Payments $ 8.2
Indiana Michigan Power Co [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 15 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following tables show the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Future minimum lease payments consisted of the following as of December 31, 2016 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9 Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of December 31, 2016 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2016 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2017 $ 147.8 $ 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 Later Years 147.2 73.6 Total Future Minimum Lease Payments $ 886.2 $ 443.1 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2016 . These obligations are included in the future minimum lease payments schedule earlier in this note. Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 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)” section of Note 7 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2026. As of December 31, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $85 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2016 , AEP’s boat and barge lease guarantee liability was $13 million , of which $2 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. During 2016, the lease term came to an end and the lease obligation was paid in full. As of December 31, 2015, these capital lease assets were included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations were included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $8 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2016 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2017 $ 5.8 2018 2.4 Total Future Minimum Lease Payments $ 8.2
Ohio Power Co [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 15 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following tables show the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Future minimum lease payments consisted of the following as of December 31, 2016 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9 Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of December 31, 2016 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2016 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2017 $ 147.8 $ 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 Later Years 147.2 73.6 Total Future Minimum Lease Payments $ 886.2 $ 443.1 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2016 . These obligations are included in the future minimum lease payments schedule earlier in this note. Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 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)” section of Note 7 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2026. As of December 31, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $85 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2016 , AEP’s boat and barge lease guarantee liability was $13 million , of which $2 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. During 2016, the lease term came to an end and the lease obligation was paid in full. As of December 31, 2015, these capital lease assets were included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations were included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $8 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2016 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2017 $ 5.8 2018 2.4 Total Future Minimum Lease Payments $ 8.2
Public Service Co Of Oklahoma [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 15 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following tables show the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Future minimum lease payments consisted of the following as of December 31, 2016 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9 Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of December 31, 2016 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2016 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2017 $ 147.8 $ 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 Later Years 147.2 73.6 Total Future Minimum Lease Payments $ 886.2 $ 443.1 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2016 . These obligations are included in the future minimum lease payments schedule earlier in this note. Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 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)” section of Note 7 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2026. As of December 31, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $85 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2016 , AEP’s boat and barge lease guarantee liability was $13 million , of which $2 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. During 2016, the lease term came to an end and the lease obligation was paid in full. As of December 31, 2015, these capital lease assets were included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations were included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $8 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2016 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2017 $ 5.8 2018 2.4 Total Future Minimum Lease Payments $ 8.2
Southwestern Electric Power Co [Member]
Leases	LEASES The disclosures in this note apply to all Registrants unless indicated otherwise. Leases of property, plant and equipment are for remaining periods up to 15 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information. The following tables show the property, plant and equipment under capital leases and related obligations recorded on the Registrants’ balance sheets. Unless shown as a separate line on the balance sheets due to materiality, current capital lease obligations are included in Other Current Liabilities and long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the Registrants’ balance sheets. December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5 Future minimum lease payments consisted of the following as of December 31, 2016 : Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9 Master Lease Agreements The Registrants lease certain equipment under master lease agreements. Under the lease agreements, the lessor is guaranteed a residual value up to a stated percentage of either the unamortized balance or the equipment cost at the end of the lease term. If the actual fair value of the leased equipment is below the guaranteed residual value at the end of the lease term, the Registrants are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of December 31, 2016 , the maximum potential loss by the Registrants for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term is as follows: Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5 Rockport Lease (Applies to AEP and I&M) AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant, Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it equally to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. AEP, AEGCo and I&M have no ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2016 are as follows: Future Minimum Lease Payments AEP (a) I&M (in millions) 2017 $ 147.8 $ 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 Later Years 147.2 73.6 Total Future Minimum Lease Payments $ 886.2 $ 443.1 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M. Railcar Lease (Applies to AEP, I&M and SWEPCo) In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignment is accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $9 million and $10 million for I&M and SWEPCo, respectively, for the remaining railcars as of December 31, 2016 . These obligations are included in the future minimum lease payments schedule earlier in this note. Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% of the projected fair value of the equipment under the current five-year lease term to 77% at the end of the 20-year term. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are $8 million and $10 million for I&M and SWEPCo, respectively, as of December 31, 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)” section of Note 7 . Certain of the boat and barge leases acquired by the nonaffiliated party are subject to an AEP guarantee in favor of the lessor, ensuring future payments under such leases with maturities up to 2026. As of December 31, 2016 , the maximum potential amount of future payments required under the guaranteed leases was $85 million . In certain instances, AEP has no recourse against the nonaffiliated party if required to pay a lessor under a guarantee, but AEP would have access to sell the leased assets in order to recover payments made by AEP under the guarantee. As of December 31, 2016 , AEP’s boat and barge lease guarantee liability was $13 million , of which $2 million was recorded in Other Current Liabilities and $11 million was recorded in Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets. Sabine Dragline Lease (Applies to AEP and SWEPCo) During 2009, Sabine entered into capital lease arrangements with a nonaffiliated company to finance the purchase of two electric draglines to be used for Sabine’s mining operations totaling $47 million . The amounts included in the lease represented the aggregate fair value of the existing equipment and a sale-and-leaseback transaction for additional dragline rebuild costs required to keep the dragline operational. During 2016, the lease term came to an end and the lease obligation was paid in full. As of December 31, 2015, these capital lease assets were included in Other Property, Plant and Equipment on the balance sheets. The short-term and long-term capital lease obligations were included in Other Current Liabilities and Deferred Credits and Other Noncurrent Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on SWEPCo’s balance sheets. I&M Nuclear Fuel Lease (Applies to AEP and I&M) In November 2013, I&M entered into a sale-and-leaseback transaction with IMP 11-2013, a nonaffiliated Ohio trust, to lease nuclear fuel for I&M’s Cook Plant. In November 2013, I&M sold a portion of its unamortized nuclear fuel inventory to the trust for $110 million . The lease has a variable rate based on one month LIBOR and is accounted for as a capital lease with lease terms up to 54 months . The future payment obligations of $8 million are included in I&M’s future minimum lease payments schedule earlier in this note. The net capital lease asset is included in Other Property, Plant and Equipment on the balance sheets. The short-term capital lease obligations are included in Other Current Liabilities on AEP’s balance sheets and in Obligations Under Capital Leases on I&M’s balance sheets. The long-term capital lease obligations are included in Deferred Credits and Other Noncurrent Liabilities on the balance sheets. The future minimum lease payments for the sale-and-leaseback transaction as of December 31, 2016 are as follows, based on estimated fuel burn: Future Minimum Lease Payments I&M (in millions) 2017 $ 5.8 2018 2.4 Total Future Minimum Lease Payments $ 8.2

Financing Activities

Financing Activities	12 Months Ended
	Dec. 31, 2016
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592 Long-term Debt The following table details long-term debt outstanding: Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information. Long-term debt outstanding as of December 31, 2016 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1 (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 7 for additional information. In January and February 2017 , I&M retired $20 million and $7 million , respectively, of Notes Payable related to DCC Fuel. In January 2017 , APCo retired $104 million of variable rate Pollution Control Bonds due in 2017 . In January 2017 , OPCo retired $22 million of Securitization Bonds. In January 2017 , SWEPCo retired $250 million of 5.55% Senior Unsecured Notes due in 2017 . In January 2017 , AEP Texas retired $90 million of Securitization Bonds. In January 2017 , AGR retired $500 million of variable rate Other Long-term Debt due in 2017 . In February 2017 , APCo retired $12 million of Securitization Bonds. In February 2017 , SWEPCo retired $2 million of Other Long-term Debt. As of December 31, 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 Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries also have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2016 , the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $10.9 billion . As of December 31, 2016 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. However, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2016 , the amount of any such restrictions was as follows: APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9 Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2016 , AEP had $6.4 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.1 billion , $1.1 billion and $1 billion of dividends to common shareholders for the years ended December 31, 2016 , 2015 and 2014 , respectively. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2016 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2016 was $1.5 billion and the weighted average interest rate of commercial paper outstanding during 2016 was 0.80% . AEP’s outstanding short-term debt was as follows: December 31, 2016 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 673.0 0.70 % $ 675.0 0.30 % Commercial Paper 1,040.0 1.02 % 125.0 0.81 % Total Short-term Debt $ 1,713.0 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2016 and 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 are described in the following tables: Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 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: Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2016 1.02 % 0.69 % 0.82 % Interest expense related to short-term borrowing activities with the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2 Interest income related to short-term lending activities with the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 — Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, on SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $16 thousand of interest income for the year ended December 31, 2016 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2016 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.70 % 0.30 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 23.7 $ 34.1 $ 40.1 December 31, 2016 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 945.0 $ 924.8 Short-term – Securitized Debt of Receivables 673.0 675.0 Delinquent Securitized Accounts Receivable 42.7 48.3 Bad Debt Reserves Related to Securitization 27.7 17.5 Unbilled Receivables Related to Securitization 322.1 357.8 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Appalachian Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592 Long-term Debt The following table details long-term debt outstanding: Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information. Long-term debt outstanding as of December 31, 2016 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1 (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 7 for additional information. In January and February 2017 , I&M retired $20 million and $7 million , respectively, of Notes Payable related to DCC Fuel. In January 2017 , APCo retired $104 million of variable rate Pollution Control Bonds due in 2017 . In January 2017 , OPCo retired $22 million of Securitization Bonds. In January 2017 , SWEPCo retired $250 million of 5.55% Senior Unsecured Notes due in 2017 . In January 2017 , AEP Texas retired $90 million of Securitization Bonds. In January 2017 , AGR retired $500 million of variable rate Other Long-term Debt due in 2017 . In February 2017 , APCo retired $12 million of Securitization Bonds. In February 2017 , SWEPCo retired $2 million of Other Long-term Debt. As of December 31, 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 Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries also have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2016 , the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $10.9 billion . As of December 31, 2016 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. However, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2016 , the amount of any such restrictions was as follows: APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9 Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2016 , AEP had $6.4 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.1 billion , $1.1 billion and $1 billion of dividends to common shareholders for the years ended December 31, 2016 , 2015 and 2014 , respectively. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2016 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2016 was $1.5 billion and the weighted average interest rate of commercial paper outstanding during 2016 was 0.80% . AEP’s outstanding short-term debt was as follows: December 31, 2016 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 673.0 0.70 % $ 675.0 0.30 % Commercial Paper 1,040.0 1.02 % 125.0 0.81 % Total Short-term Debt $ 1,713.0 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2016 and 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 are described in the following tables: Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 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: Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2016 1.02 % 0.69 % 0.82 % Interest expense related to short-term borrowing activities with the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2 Interest income related to short-term lending activities with the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 — Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, on SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $16 thousand of interest income for the year ended December 31, 2016 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2016 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.70 % 0.30 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 23.7 $ 34.1 $ 40.1 December 31, 2016 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 945.0 $ 924.8 Short-term – Securitized Debt of Receivables 673.0 675.0 Delinquent Securitized Accounts Receivable 42.7 48.3 Bad Debt Reserves Related to Securitization 27.7 17.5 Unbilled Receivables Related to Securitization 322.1 357.8 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Indiana Michigan Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592 Long-term Debt The following table details long-term debt outstanding: Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information. Long-term debt outstanding as of December 31, 2016 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1 (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 7 for additional information. In January and February 2017 , I&M retired $20 million and $7 million , respectively, of Notes Payable related to DCC Fuel. In January 2017 , APCo retired $104 million of variable rate Pollution Control Bonds due in 2017 . In January 2017 , OPCo retired $22 million of Securitization Bonds. In January 2017 , SWEPCo retired $250 million of 5.55% Senior Unsecured Notes due in 2017 . In January 2017 , AEP Texas retired $90 million of Securitization Bonds. In January 2017 , AGR retired $500 million of variable rate Other Long-term Debt due in 2017 . In February 2017 , APCo retired $12 million of Securitization Bonds. In February 2017 , SWEPCo retired $2 million of Other Long-term Debt. As of December 31, 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 Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries also have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2016 , the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $10.9 billion . As of December 31, 2016 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. However, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2016 , the amount of any such restrictions was as follows: APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9 Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2016 , AEP had $6.4 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.1 billion , $1.1 billion and $1 billion of dividends to common shareholders for the years ended December 31, 2016 , 2015 and 2014 , respectively. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2016 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2016 was $1.5 billion and the weighted average interest rate of commercial paper outstanding during 2016 was 0.80% . AEP’s outstanding short-term debt was as follows: December 31, 2016 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 673.0 0.70 % $ 675.0 0.30 % Commercial Paper 1,040.0 1.02 % 125.0 0.81 % Total Short-term Debt $ 1,713.0 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2016 and 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 are described in the following tables: Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 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: Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2016 1.02 % 0.69 % 0.82 % Interest expense related to short-term borrowing activities with the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2 Interest income related to short-term lending activities with the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 — Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, on SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $16 thousand of interest income for the year ended December 31, 2016 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2016 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.70 % 0.30 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 23.7 $ 34.1 $ 40.1 December 31, 2016 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 945.0 $ 924.8 Short-term – Securitized Debt of Receivables 673.0 675.0 Delinquent Securitized Accounts Receivable 42.7 48.3 Bad Debt Reserves Related to Securitization 27.7 17.5 Unbilled Receivables Related to Securitization 322.1 357.8 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Ohio Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592 Long-term Debt The following table details long-term debt outstanding: Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information. Long-term debt outstanding as of December 31, 2016 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1 (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 7 for additional information. In January and February 2017 , I&M retired $20 million and $7 million , respectively, of Notes Payable related to DCC Fuel. In January 2017 , APCo retired $104 million of variable rate Pollution Control Bonds due in 2017 . In January 2017 , OPCo retired $22 million of Securitization Bonds. In January 2017 , SWEPCo retired $250 million of 5.55% Senior Unsecured Notes due in 2017 . In January 2017 , AEP Texas retired $90 million of Securitization Bonds. In January 2017 , AGR retired $500 million of variable rate Other Long-term Debt due in 2017 . In February 2017 , APCo retired $12 million of Securitization Bonds. In February 2017 , SWEPCo retired $2 million of Other Long-term Debt. As of December 31, 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 Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries also have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2016 , the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $10.9 billion . As of December 31, 2016 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. However, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2016 , the amount of any such restrictions was as follows: APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9 Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2016 , AEP had $6.4 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.1 billion , $1.1 billion and $1 billion of dividends to common shareholders for the years ended December 31, 2016 , 2015 and 2014 , respectively. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2016 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2016 was $1.5 billion and the weighted average interest rate of commercial paper outstanding during 2016 was 0.80% . AEP’s outstanding short-term debt was as follows: December 31, 2016 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 673.0 0.70 % $ 675.0 0.30 % Commercial Paper 1,040.0 1.02 % 125.0 0.81 % Total Short-term Debt $ 1,713.0 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2016 and 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 are described in the following tables: Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 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: Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2016 1.02 % 0.69 % 0.82 % Interest expense related to short-term borrowing activities with the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2 Interest income related to short-term lending activities with the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 — Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, on SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $16 thousand of interest income for the year ended December 31, 2016 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2016 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.70 % 0.30 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 23.7 $ 34.1 $ 40.1 December 31, 2016 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 945.0 $ 924.8 Short-term – Securitized Debt of Receivables 673.0 675.0 Delinquent Securitized Accounts Receivable 42.7 48.3 Bad Debt Reserves Related to Securitization 27.7 17.5 Unbilled Receivables Related to Securitization 322.1 357.8 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Public Service Co Of Oklahoma [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592 Long-term Debt The following table details long-term debt outstanding: Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information. Long-term debt outstanding as of December 31, 2016 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1 (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 7 for additional information. In January and February 2017 , I&M retired $20 million and $7 million , respectively, of Notes Payable related to DCC Fuel. In January 2017 , APCo retired $104 million of variable rate Pollution Control Bonds due in 2017 . In January 2017 , OPCo retired $22 million of Securitization Bonds. In January 2017 , SWEPCo retired $250 million of 5.55% Senior Unsecured Notes due in 2017 . In January 2017 , AEP Texas retired $90 million of Securitization Bonds. In January 2017 , AGR retired $500 million of variable rate Other Long-term Debt due in 2017 . In February 2017 , APCo retired $12 million of Securitization Bonds. In February 2017 , SWEPCo retired $2 million of Other Long-term Debt. As of December 31, 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 Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries also have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2016 , the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $10.9 billion . As of December 31, 2016 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. However, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2016 , the amount of any such restrictions was as follows: APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9 Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2016 , AEP had $6.4 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.1 billion , $1.1 billion and $1 billion of dividends to common shareholders for the years ended December 31, 2016 , 2015 and 2014 , respectively. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2016 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2016 was $1.5 billion and the weighted average interest rate of commercial paper outstanding during 2016 was 0.80% . AEP’s outstanding short-term debt was as follows: December 31, 2016 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 673.0 0.70 % $ 675.0 0.30 % Commercial Paper 1,040.0 1.02 % 125.0 0.81 % Total Short-term Debt $ 1,713.0 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2016 and 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 are described in the following tables: Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 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: Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2016 1.02 % 0.69 % 0.82 % Interest expense related to short-term borrowing activities with the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2 Interest income related to short-term lending activities with the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 — Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, on SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $16 thousand of interest income for the year ended December 31, 2016 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2016 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.70 % 0.30 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 23.7 $ 34.1 $ 40.1 December 31, 2016 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 945.0 $ 924.8 Short-term – Securitized Debt of Receivables 673.0 675.0 Delinquent Securitized Accounts Receivable 42.7 48.3 Bad Debt Reserves Related to Securitization 27.7 17.5 Unbilled Receivables Related to Securitization 322.1 357.8 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Southwestern Electric Power Co [Member]
Financing Activities	FINANCING ACTIVITIES The disclosures in this note apply to all Registrants unless indicated otherwise. Common Stock (Applies to AEP) Listed below is a reconciliation of common stock share activity: Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592 Long-term Debt The following table details long-term debt outstanding: Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information. Long-term debt outstanding as of December 31, 2016 is payable as follows: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1 (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 7 for additional information. In January and February 2017 , I&M retired $20 million and $7 million , respectively, of Notes Payable related to DCC Fuel. In January 2017 , APCo retired $104 million of variable rate Pollution Control Bonds due in 2017 . In January 2017 , OPCo retired $22 million of Securitization Bonds. In January 2017 , SWEPCo retired $250 million of 5.55% Senior Unsecured Notes due in 2017 . In January 2017 , AEP Texas retired $90 million of Securitization Bonds. In January 2017 , AGR retired $500 million of variable rate Other Long-term Debt due in 2017 . In February 2017 , APCo retired $12 million of Securitization Bonds. In February 2017 , SWEPCo retired $2 million of Other Long-term Debt. As of December 31, 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 Utility Subsidiaries’ Restrictions Parent depends on its utility subsidiaries to pay dividends to shareholders. AEP utility subsidiaries pay dividends to Parent provided funds are legally available. Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of the subsidiaries to transfer funds to Parent in the form of dividends. All of the dividends declared by AEP’s utility subsidiaries that provide transmission or local distribution services are subject to a Federal Power Act restriction that prohibits the payment of dividends out of capital accounts without regulatory approval; payment of dividends is allowed out of retained earnings only. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their ownership of such plants, this reserve applies to AGR, APCo and I&M. Certain AEP subsidiaries also have credit agreements that contain covenants that limit their debt to capitalization ratio to 67.5% . The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the AEP subsidiary distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. The most restrictive dividend limitation for certain AEP subsidiaries is through the Federal Power Act restriction, while for other AEP subsidiaries the most restrictive dividend limitation is through the credit agreements. As of December 31, 2016 , the maximum amount of restricted net assets of AEP’s subsidiaries that may not be distributed to the Parent in the form of a loan, advance or dividend was $10.9 billion . As of December 31, 2016 , the Federal Power Act restriction does not limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. However, the credit agreement covenant restrictions can limit the ability of the AEP subsidiaries to pay dividends out of retained earnings. As of December 31, 2016 , the amount of any such restrictions was as follows: APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9 Parent Restrictions (Applies to AEP) The holders of AEP’s common stock are entitled to receive the dividends declared by the Board of Directors provided funds are legally available for such dividends. Parent’s income primarily derives from common stock equity in the earnings of its utility subsidiaries. Pursuant to the leverage restrictions in credit agreements, AEP must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%. The payment of cash dividends indirectly results in an increase in the percentage of debt to total capitalization of the company distributing the dividend. The method for calculating outstanding debt and capitalization is contractually defined in the credit agreements. As of December 31, 2016 , AEP had $6.4 billion of available retained earnings to pay dividends to common shareholders. AEP paid $1.1 billion , $1.1 billion and $1 billion of dividends to common shareholders for the years ended December 31, 2016 , 2015 and 2014 , respectively. Lines of Credit and Short-term Debt (Applies to AEP) AEP uses its commercial paper program to meet the short-term borrowing needs of its subsidiaries. The program is used to fund both a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds certain of the nonutility subsidiaries. In addition, the program also funds, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of December 31, 2016 , AEP had credit facilities totaling $3.5 billion to support its commercial paper program. The maximum amount of commercial paper outstanding during 2016 was $1.5 billion and the weighted average interest rate of commercial paper outstanding during 2016 was 0.80% . AEP’s outstanding short-term debt was as follows: December 31, 2016 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 673.0 0.70 % $ 675.0 0.30 % Commercial Paper 1,040.0 1.02 % 125.0 0.81 % Total Short-term Debt $ 1,713.0 $ 800.0 (a) Weighted average rate. (b) Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance. Corporate Borrowing Program – AEP System (Applies to Registrant Subsidiaries) The AEP System uses a corporate borrowing program to meet the short-term borrowing needs of AEP’s subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds AEP’s utility subsidiaries, and a Nonutility Money Pool, which funds certain AEP nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of December 31, 2016 and 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 are described in the following tables: Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0 The activity in the above tables does not include short-term lending activity of SWEPCo’s wholly-owned subsidiary, Mutual Energy SWEPCo, LLC, which is a participant in the Nonutility Money Pool. The amounts of outstanding loans to the Nonutility Money Pool as of December 31, 2016 are included in Advances to Affiliates on SWEPCo’s balance sheets. For the year ended December 31, 2016 , Mutual Energy SWEPCo, LLC had the following activity in the Nonutility Money Pool: Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 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: Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 % Maximum, minimum and average interest rates for funds loaned to the Nonutility Money Pool are summarized for Mutual Energy SWEPCo, LLC in the following table: Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2016 1.02 % 0.69 % 0.82 % Interest expense related to short-term borrowing activities with the Utility Money Pool is included in Interest Expense on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries incurred interest expense for all short-term borrowing activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2 Interest income related to short-term lending activities with the Utility Money Pool is included in Interest Income on each of the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries earned interest income for all short-term lending activities as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 — Interest expense and interest income related to the Nonutility Money Pool are included in Interest Expense and Interest Income, respectively, on SWEPCo’s statements of income. For amounts borrowed from and advanced to the Nonutility Money Pool, SWEPCo incurred $16 thousand of interest income for the year ended December 31, 2016 . Credit Facilities For a discussion of credit facilities, see “Letters of Credit” section of Note 6 . Securitized Accounts Receivables – AEP Credit (Applies to AEP) AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from the bank conduits for the interest in the receivables AEP Credit acquires from affiliated utility subsidiaries. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase the operating companies’ receivables and accelerate AEP Credit’s cash collections. AEP Credit’s receivables securitization agreement provides a commitment of $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2018. Accounts receivable information for AEP Credit is as follows: Years Ended December 31, 2016 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.70 % 0.30 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 23.7 $ 34.1 $ 40.1 December 31, 2016 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 945.0 $ 924.8 Short-term – Securitized Debt of Receivables 673.0 675.0 Delinquent Securitized Accounts Receivable 42.7 48.3 Bad Debt Reserves Related to Securitization 27.7 17.5 Unbilled Receivables Related to Securitization 322.1 357.8 AEP Credit’s delinquent customer accounts receivable represent accounts greater than 30 days past due. Securitized Accounts Receivables – AEP Credit (Applies to Registrant Subsidiaries) Under this sale of receivables arrangement, the Registrant Subsidiaries sell, without recourse, certain of their customer accounts receivable and accrued unbilled revenue balances to AEP Credit and are charged a fee based on AEP Credit’s financing costs, administrative costs and uncollectible accounts experience for each Registrant Subsidiary’s receivables. APCo does not have regulatory authority to sell its West Virginia accounts receivable. The costs of customer accounts receivable sold are reported in Other Operation expense on the Registrant Subsidiaries’ statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable, which are sold to AEP Credit. AEP Credit securitizes the eligible receivables for the operating companies and retains the remainder. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary was as follows: December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2016
Stock-based Compensation	STOCK-BASED COMPENSATION The disclosures in this note apply to AEP only. The impact of AEP’s share-based compensation plans is insignificant to the financial statements of the Registrant Subsidiaries. AEP’s long-term incentive plan available for eligible employees and directors, the Amended and Restated American Electric Power System Long-Term Incentive Plan (the “Prior Plan”), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (the “2015 LTIP”) effective in April 2015. The 2015 LTIP provides for a maximum of 10 million common shares to be available for grant to eligible employees and directors. As of December 31, 2016 , 9,822,644 shares remained available for issuance under the 2015 LTIP plan. No new awards may be granted under the Prior Plan. To the extent the issuance of a share that is subject to an outstanding award under the Prior Plan, the issuance of that share will take place under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards and other stock-based awards. If a share is issued pursuant to a stock option or a stock appreciation right, it will reduce the aggregate amount authorized under the 2015 LTIP by 0.286 of a share. If a share is issued for any other award that settles in AEP stock, it will reduce the aggregate amount authorized under the 2015 LTIP by one share. Cash settled awards do not reduce the aggregate amount authorized under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted by the Human Resources Committee of AEP’s Board of Directors (HR Committee). Performance Units AEP’s performance units are paid out in cash rather than AEP shares and do not reduce the aggregate share authorization. AEP’s performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. The number of performance units held at the end of the three year performance period is multiplied by the performance score to determine the actual number of performance units realized. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the HR Committee. Certain employees must satisfy stock ownership requirements. If those employees have not met their stock ownership requirements, a portion or all of their performance units are mandatorily deferred as AEP career shares to the extent needed to meet their stock ownership requirement. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock. AEP career shares are paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and AEP career shares accrue as additional units. Management records compensation cost for performance units over a three-year vesting period. The liability for both the performance units and AEP career shares, recorded in Employee Benefits and Pension Obligations on the balance sheets, is adjusted for changes in value. The HR Committee awarded performance units and reinvested dividends on outstanding performance units and AEP career shares for the years ended December 31, 2016 , 2015 and 2014 as follows: Years Ended December 31, Performance Units 2016 2015 2014 Awarded Units (in thousands) 597.4 575.0 16.9 Weighted Average Unit Fair Value at Grant Date $ 62.77 $ 59.19 $ 49.73 Vesting Period (in years) 3 3 3 Performance Units and AEP Career Shares (Reinvested Dividends Portion) Years Ended December 31, 2016 2015 2014 Awarded Units (in thousands) 89.2 103.6 98.9 Weighted Average Fair Value at Grant Date $ 63.83 $ 54.35 $ 53.35 Vesting Period (in years) (a) (a) (a) (a) The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP career shares vest immediately when the dividend is awarded but are not paid in cash until after the participant’s AEP employment ends. Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period. The performance scores for all performance periods were dependent on two equally-weighted performance measures: (a) three -year total shareholder return measured relative to the Standard and Poor’s 500 Electric Utilities Index and (b) three -year cumulative earnings per share measured relative to a target approved by AEP’s Board of Directors. The certified performance scores and units earned for the three-year periods ended December 31, 2016 , 2015 and 2014 were as follows: Years Ended December 31, Performance Units 2016 2015 2014 Certified Performance Score 163.9 % 176.3 % 147.8 % Performance Units Earned 1,111,966 1,202,107 889,697 Performance Units Mandatorily Deferred as AEP Career Shares 9,963 41,707 40,831 Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program 51,684 54,074 39,526 Performance Units to be Paid in Cash 1,050,319 1,106,326 809,340 The cash payouts for the years ended December 31, 2016 , 2015 and 2014 were as follows: Years Ended December 31, Performance Units and AEP Career Shares 2016 2015 2014 (in millions) Cash Payouts for Performance Units $ 62.7 $ 48.1 $ 29.3 Cash Payouts for AEP Career Share Distributions 9.1 3.0 4.3 Restricted Stock Units The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into a share of AEP common stock upon vesting, except for AEP’s officers subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, who are paid in cash. In 2014, there were no RSUs granted to Section 16 officers due to a change that deferred granting these and other awards until February 2015. For RSUs paid in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs paid in cash, compensation cost is recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting is determined by multiplying the number of RSUs vested by the 20 -day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date. In 2010, the HR Committee granted a total of 165,520 RSUs to four Chief Executive Officer succession candidates as a retention incentive for these candidates. These grants vested in three approximately equal installments in August 2013, August 2014 and August 2015. The HR Committee awarded RSUs, including additional units awarded as dividends, for the years ended December 31, 2016 , 2015 and 2014 as follows: Years Ended December 31, Restricted Stock Units 2016 2015 2014 Awarded Units (in thousands) 242.0 397.5 64.1 Weighted Average Grant Date Fair Value $ 62.88 $ 58.56 $ 50.36 The total fair value and total intrinsic value of restricted stock units vested during the years ended December 31, 2016 , 2015 and 2014 were as follows: Years Ended December 31, Restricted Stock Units 2016 2015 2014 (in millions) Fair Value of Restricted Stock Units Vested $ 16.4 $ 18.3 $ 18.7 Intrinsic Value of Restricted Stock Units Vested (a) 21.0 24.2 24.9 (a) Intrinsic value is calculated as market price at exercise date. A summary of the status of AEP’s nonvested RSUs as of December 31, 2016 and changes during the year ended December 31, 2016 are as follows: Nonvested Restricted Stock Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2016 721.3 $ 52.48 Granted 242.0 62.88 Vested (326.7 ) 50.07 Forfeited (33.0 ) 55.81 Nonvested as of December 31, 2016 603.6 57.54 The total aggregate intrinsic value of nonvested RSUs as of December 31, 2016 was $38 million and the weighted average remaining contractual life was 1.7 years . Other Stock-Based Plans AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to Non-Employee Directors are fully vested upon grant date. Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects. Cash payments for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. After five years of service on the Board of Directors, non-employee directors receive contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investments that are similar to the investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20 -day average closing price of AEP common stock on the valuation date. The cash payouts for stock unit distributions for the years ended December 31, 2016 , 2015 and 2014 were $0 million , $1 million and $5 million , respectively. The Board of Directors awarded stock units, including units awarded for dividends, for the years ended December 31, 2016 , 2015 and 2014 as follows: Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2016 2015 2014 Awarded Units (in thousands) 19.1 24.9 25.4 Weighted Average Grant Date Fair Value $ 64.96 $ 55.46 $ 54.08 Share-based Compensation Plans Compensation cost for share-based payment arrangements, the actual tax benefit realized from the tax deductions for compensation cost for share-based payment arrangements recognized in income and total compensation cost capitalized in relation to the cost of an asset for the years ended December 31, 2016 , 2015 and 2014 were as follows: Years Ended December 31, Share-based Compensation Plans 2016 2015 2014 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 66.5 $ 63.8 $ 85.4 Actual Tax Benefit Realized 23.3 22.3 29.9 Total Compensation Cost Capitalized 20.8 20.3 23.1 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income. During the years ended December 31, 2016 , 2015 and 2014 , there were no significant modifications affecting any of AEP’s share-based payment arrangements. As of December 31, 2016 , there was $62 million of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the 2015 LTIP and Prior Plan. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance units and AEP career shares is adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.37 years . AEP’s practice prior to August 2016 was to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting. In August 2016, AEP began also using shares purchased on the open market to fulfill such share commitments. AEP is permitted to use treasury shares, shares acquired in the open market specifically for distribution under the 2015 LTIP and Prior Plan or any combination thereof for this purpose. Management anticipates using a combination of open market purchases and treasury shares for this purpose going forward. The number of new shares issued to fulfill vesting RSUs is generally reduced to offset AEP’s tax withholding obligation.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Appalachian Power Co [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. Further, the Restated and Amended PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR committed to use its capacity to help meet the PJM capacity obligations of member companies through the PJM planning year that ended May 31, 2015. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2016 , 2015 and 2014 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2016 , 2015 and 2014 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. (c) Amounts exclude $31 million and $157 million in 2015 and 2014, respectively, which are now presented as Generation Deferrals on the Statement of Income. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2016 , 2015 and 2014 related to the TA: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 103.2 $ 92.7 $ 84.7 I&M 53.0 38.0 39.7 OPCo 143.6 81.0 17.0 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2016 , 2015 and 2014 : Years Ended December 31, Company 2016 2015 2014 (in millions) PSO $ 19.6 $ 15.0 $ 14.1 SWEPCo (19.6 ) (15.0 ) (14.1 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M) UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, PSO and SWEPCo) Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading expenses in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 12.8 $ 15.8 $ 16.2 I&M recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance revenues in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 1.7 $ 2.0 $ 2.5 PSO 0.6 0.2 0.3 SWEPCo 3.3 2.8 3.3 I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ 14.8 $ 16.1 $ 22.7 AGR 0.3 4.9 5.2 APCo 36.9 37.7 36.1 KPCo 5.3 4.6 5.0 WPCo 4.8 — — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — 15.5 25.3 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 and 2014 , I&M recorded expenses of $19 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2016 , the ownership and investment in OVEC were as follows: December 31, 2016 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2016, OVEC’s outstanding indebtedness is approximately $1.5 billion . The Registrants’ are responsible for their 43.47% share of OVEC’s outstanding debt. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 . Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2016 , 2015 and 2014 were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 88.0 $ 87.2 $ 96.9 I&M 44.0 43.7 48.5 OPCo 111.7 110.8 123.1 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2016 , 2015 and 2014 : Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2 Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Indiana Michigan Power Co [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. Further, the Restated and Amended PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR committed to use its capacity to help meet the PJM capacity obligations of member companies through the PJM planning year that ended May 31, 2015. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2016 , 2015 and 2014 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2016 , 2015 and 2014 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. (c) Amounts exclude $31 million and $157 million in 2015 and 2014, respectively, which are now presented as Generation Deferrals on the Statement of Income. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2016 , 2015 and 2014 related to the TA: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 103.2 $ 92.7 $ 84.7 I&M 53.0 38.0 39.7 OPCo 143.6 81.0 17.0 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2016 , 2015 and 2014 : Years Ended December 31, Company 2016 2015 2014 (in millions) PSO $ 19.6 $ 15.0 $ 14.1 SWEPCo (19.6 ) (15.0 ) (14.1 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M) UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, PSO and SWEPCo) Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading expenses in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 12.8 $ 15.8 $ 16.2 I&M recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance revenues in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 1.7 $ 2.0 $ 2.5 PSO 0.6 0.2 0.3 SWEPCo 3.3 2.8 3.3 I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ 14.8 $ 16.1 $ 22.7 AGR 0.3 4.9 5.2 APCo 36.9 37.7 36.1 KPCo 5.3 4.6 5.0 WPCo 4.8 — — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — 15.5 25.3 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 and 2014 , I&M recorded expenses of $19 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2016 , the ownership and investment in OVEC were as follows: December 31, 2016 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2016, OVEC’s outstanding indebtedness is approximately $1.5 billion . The Registrants’ are responsible for their 43.47% share of OVEC’s outstanding debt. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 . Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2016 , 2015 and 2014 were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 88.0 $ 87.2 $ 96.9 I&M 44.0 43.7 48.5 OPCo 111.7 110.8 123.1 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2016 , 2015 and 2014 : Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2 Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Ohio Power Co [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. Further, the Restated and Amended PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR committed to use its capacity to help meet the PJM capacity obligations of member companies through the PJM planning year that ended May 31, 2015. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2016 , 2015 and 2014 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2016 , 2015 and 2014 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. (c) Amounts exclude $31 million and $157 million in 2015 and 2014, respectively, which are now presented as Generation Deferrals on the Statement of Income. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2016 , 2015 and 2014 related to the TA: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 103.2 $ 92.7 $ 84.7 I&M 53.0 38.0 39.7 OPCo 143.6 81.0 17.0 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2016 , 2015 and 2014 : Years Ended December 31, Company 2016 2015 2014 (in millions) PSO $ 19.6 $ 15.0 $ 14.1 SWEPCo (19.6 ) (15.0 ) (14.1 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M) UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, PSO and SWEPCo) Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading expenses in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 12.8 $ 15.8 $ 16.2 I&M recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance revenues in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 1.7 $ 2.0 $ 2.5 PSO 0.6 0.2 0.3 SWEPCo 3.3 2.8 3.3 I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ 14.8 $ 16.1 $ 22.7 AGR 0.3 4.9 5.2 APCo 36.9 37.7 36.1 KPCo 5.3 4.6 5.0 WPCo 4.8 — — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — 15.5 25.3 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 and 2014 , I&M recorded expenses of $19 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2016 , the ownership and investment in OVEC were as follows: December 31, 2016 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2016, OVEC’s outstanding indebtedness is approximately $1.5 billion . The Registrants’ are responsible for their 43.47% share of OVEC’s outstanding debt. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 . Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2016 , 2015 and 2014 were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 88.0 $ 87.2 $ 96.9 I&M 44.0 43.7 48.5 OPCo 111.7 110.8 123.1 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2016 , 2015 and 2014 : Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2 Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Public Service Co Of Oklahoma [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. Further, the Restated and Amended PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR committed to use its capacity to help meet the PJM capacity obligations of member companies through the PJM planning year that ended May 31, 2015. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2016 , 2015 and 2014 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2016 , 2015 and 2014 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. (c) Amounts exclude $31 million and $157 million in 2015 and 2014, respectively, which are now presented as Generation Deferrals on the Statement of Income. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2016 , 2015 and 2014 related to the TA: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 103.2 $ 92.7 $ 84.7 I&M 53.0 38.0 39.7 OPCo 143.6 81.0 17.0 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2016 , 2015 and 2014 : Years Ended December 31, Company 2016 2015 2014 (in millions) PSO $ 19.6 $ 15.0 $ 14.1 SWEPCo (19.6 ) (15.0 ) (14.1 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M) UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, PSO and SWEPCo) Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading expenses in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 12.8 $ 15.8 $ 16.2 I&M recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance revenues in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 1.7 $ 2.0 $ 2.5 PSO 0.6 0.2 0.3 SWEPCo 3.3 2.8 3.3 I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ 14.8 $ 16.1 $ 22.7 AGR 0.3 4.9 5.2 APCo 36.9 37.7 36.1 KPCo 5.3 4.6 5.0 WPCo 4.8 — — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — 15.5 25.3 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 and 2014 , I&M recorded expenses of $19 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2016 , the ownership and investment in OVEC were as follows: December 31, 2016 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2016, OVEC’s outstanding indebtedness is approximately $1.5 billion . The Registrants’ are responsible for their 43.47% share of OVEC’s outstanding debt. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 . Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2016 , 2015 and 2014 were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 88.0 $ 87.2 $ 96.9 I&M 44.0 43.7 48.5 OPCo 111.7 110.8 123.1 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2016 , 2015 and 2014 : Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2 Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.
Southwestern Electric Power Co [Member]
Related Party Transactions	RELATED PARTY TRANSACTIONS The disclosures in this note apply to all Registrant Subsidiaries unless indicated otherwise. For other related party transactions, also see “AEP System Tax Allocation Agreement” section of Note 12 in addition to “Utility Money Pool – AEP System” and “Sale of Receivables – AEP Credit” sections of Note 14 . Interconnection Agreement In accordance with management’s December 2010 announcement and October 2012 filing with the FERC, the Interconnection Agreement was terminated effective January 1, 2014. The AEP System Interim Allowance Agreement which provided for, among other things, the transfer of SO 2 emission allowances associated with transactions under the Interconnection Agreement was also terminated. APCo, I&M, KPCo, OPCo and AEPSC were parties to the Interconnection Agreement which defined the sharing of costs and benefits associated with the respective generation plants. This sharing was based upon each AEP utility subsidiary’s MLR and was calculated monthly on the basis of each AEP utility subsidiary’s maximum peak demand in relation to the sum of the maximum peak demands of all four AEP utility subsidiaries during the preceding 12 months. Effective January 1, 2014, the FERC approved the following agreements. • A Power Coordination Agreement (PCA) among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Under the PCA, APCo, I&M, KPCo and WPCo are individually responsible for planning their respective capacity obligations. Further, the Restated and Amended PCA allows, but does not obligate, APCo, I&M, KPCo and WPCo to participate collectively under a common fixed resource requirement capacity plan in PJM and to participate in specified collective off-system sales and purchase activities. • A Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as agent. The Bridge Agreement is an interim arrangement to: (a) address the treatment of purchases and sales made by AEPSC on behalf of member companies that extend beyond termination of the Interconnection Agreement and (b) address how member companies would fulfill their existing obligations under the PJM Reliability Assurance Agreement through the 2014/2015 PJM planning year. Under the Bridge Agreement, AGR committed to use its capacity to help meet the PJM capacity obligations of member companies through the PJM planning year that ended May 31, 2015. • A Power Supply Agreement (PSA) between AGR and OPCo that provided for AGR to supply capacity for OPCo’s switched (at $188.88/MW day) and non-switched retail load for the period January 1, 2014 through May 31, 2015 and to supply the energy needs of OPCo’s non-switched retail load that was not acquired through auctions in 2014. AEPSC conducts power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other risk management activities on behalf of APCo, I&M, KPCo, PSO, SWEPCo and WPCo. Effective January 1, 2014 and revised in May 2015, power and natural gas risk management activities for APCo, I&M, KPCo and WPCo are allocated based on the four member companies’ respective equity positions, while power and natural gas risk management activities for PSO and SWEPCo are allocated based on the Operating Agreement. Effective January 1, 2014 and with the transfer of OPCo’s generation assets to AGR, AEPSC conducts only gasoline, diesel fuel, energy procurement and risk management activities on OPCo’s behalf. Operating Agreement (Applies to PSO and SWEPCo) PSO, SWEPCo and AEPSC are parties to the Operating Agreement which was approved by the FERC. The Operating Agreement requires PSO and SWEPCo to maintain adequate annual planning reserve margins and requires that capacity in excess of the required margins be made available for sale to other operating companies as capacity commitments. In January 2014, the FERC approved a modification of the Operating Agreement to address changes resulting from an anticipated March 2014 SPP power market change. Subsequently and in March 2014, SPP changed from an energy imbalance service market to a fully integrated power market. In alignment with the new SPP integrated power market and according to the modified Operating Agreement, PSO and SWEPCo operate as standalone entities and offer their respective generation into the SPP power market. SPP then economically dispatches resources. By offering their resources separately, PSO and SWEPCo no longer purchase or sell energy to each other to serve their respective internal load or off-system sales. System Integration Agreement (SIA) (Applies to APCo, I&M, PSO and SWEPCo) Under the SIA, AEPSC allocates physical and financial revenues and expenses from transactions with neighboring utilities, power marketers and other power and natural gas risk management activities based upon the location of such activity. Margins resulting from trading and marketing activities originating in PJM and MISO generally accrue to the benefit of APCo, I&M, KPCo and WPCo, while trading and marketing activities originating in SPP generally accrue to the benefit of PSO and SWEPCo. Margins resulting from other transactions are allocated among APCo, I&M, KPCo, PSO, SWEPCo and WPCo based upon the equity positions of these companies. Affiliated Revenues and Purchases The following tables show the revenues derived from sales under the Interconnection Agreement, direct sales to affiliates, net transmission agreement sales and other revenues for the years ended December 31, 2016 , 2015 and 2014 : Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination. The following tables show the purchased power expenses incurred for purchases under the Interconnection Agreement and from affiliates for the years ended December 31, 2016 , 2015 and 2014 : Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination. (c) Amounts exclude $31 million and $157 million in 2015 and 2014, respectively, which are now presented as Generation Deferrals on the Statement of Income. The above summarized related party revenues and expenses are reported in Sales to AEP Affiliates and Purchased Electricity from AEP Affiliates, respectively, on the Registrant Subsidiaries’ statements of income. Since the Registrant Subsidiaries are included in AEP’s consolidated results, the above summarized related party transactions are eliminated in total in AEP’s consolidated revenues and expenses. System Transmission Integration Agreement (STIA) AEP’s STIA provided for the integration and coordination of the planning, operation and maintenance of transmission facilities. Since the FERC approved the cancellation of the STIA effective June 1, 2014, the coordinated planning, operation and maintenance of transmission facilities are the responsibility of the RTOs and the STIA is no longer necessary. Similar to the SIA, the STIA functioned as an umbrella agreement in addition to the Transmission Agreement (TA) and the Transmission Coordination Agreement (TCA). The TA and TCA are both still active. The STIA contained two service schedules that governed: • The allocation of transmission costs and revenues. • The allocation of third-party transmission costs and revenues and AEP System dispatch costs. APCo, I&M, KGPCo, KPCo, OPCo and WPCo are parties to the TA, effective November 2010, which defines how transmission costs through PJM OATT are allocated among the AEP East Companies, KGPCo and WPCo on a 12-month average coincident peak basis. The following table shows the net charges recorded by the Registrant Subsidiaries for the years ended December 31, 2016 , 2015 and 2014 related to the TA: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 103.2 $ 92.7 $ 84.7 I&M 53.0 38.0 39.7 OPCo 143.6 81.0 17.0 The charges shown above are recorded in Other Operation expenses on the statements of income. PSO, SWEPCo and AEPSC are parties to the TCA, dated January 1, 1997, by and among PSO, SWEPCo and AEPSC, in connection with the operation of the transmission assets of the two AEP utility subsidiaries. The TCA has been approved by the FERC and establishes a coordinating committee, which is charged with overseeing the coordinated planning of the transmission facilities of the parties to the agreement. This includes the performance of transmission planning studies, the interaction of such companies with independent system operators (ISO) and other regional bodies interested in transmission planning and compliance with the terms of the OATT filed with the FERC and the rules of the FERC relating to such a tariff. Under the TCA, the parties to the agreement delegated to AEPSC the responsibility of monitoring the reliability of their transmission systems and administering the OATT on their behalf. The allocations have been governed by the FERC-approved OATT for the SPP. The following table shows the net (revenues) expenses allocated among parties to the TCA pursuant to the SPP OATT protocols as described above for the years ended December 31, 2016 , 2015 and 2014 : Years Ended December 31, Company 2016 2015 2014 (in millions) PSO $ 19.6 $ 15.0 $ 14.1 SWEPCo (19.6 ) (15.0 ) (14.1 ) The net (revenues) expenses shown above are recorded in Sales to AEP Affiliates on SWEPCo’s statements of income and Other Operation expenses on PSO’s statements of income. Ohio Auctions (Applies to APCo, I&M and OPCo) In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015. AEP Energy, AEPEP, APCo, KPCo, I&M and WPCo participate in the auction process and have been awarded tranches of OPCo’s SSO load. Refer to the Affiliated Revenues and Purchases section above for amounts related to these transactions. See Note 10 - Derivatives and Hedging for further information. Unit Power Agreements (UPA) (Applies to I&M) UPA between AEGCo and I&M A UPA between AEGCo and I&M (the I&M Power Agreement) provides for the sale by AEGCo to I&M of all the power (and the energy associated therewith) available to AEGCo at the Rockport Plant unless it is sold to another utility. Subsequently, I&M assigns 30% of the power to KPCo. See the “UPA between AEGCo and KPCo” section below. I&M is obligated, whether or not power is available from AEGCo, to pay as a demand charge for the right to receive such power (and as an energy charge for any associated energy taken by I&M) net of amounts received by AEGCo from any other sources, sufficient to enable AEGCo to pay all its operating and other expenses, including a rate of return on the common equity of AEGCo as approved by the FERC. The I&M Power Agreement will continue in effect until the expiration of the lease term of Unit 2 of the Rockport Plant unless extended in specified circumstances. UPA between AEGCo and KPCo Pursuant to an assignment between I&M and KPCo and a UPA between KPCo and AEGCo, AEGCo sells KPCo 30% of the power (and the energy associated therewith) available to AEGCo from both units of the Rockport Plant. KPCo pays to AEGCo in consideration for the right to receive such power the same amounts which I&M would have paid AEGCo under the terms of the I&M Power Agreement for such entitlement. The KPCo UPA ends in December 2022. Cook Coal Terminal (Applies to I&M, PSO and SWEPCo) Cook Coal Terminal, which is owned by AEGCo, performs coal transloading and storage services at cost for I&M. The coal transloading expenses in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 12.8 $ 15.8 $ 16.2 I&M recorded the cost of transloading services in Fuel on the balance sheet. Cook Coal Terminal also performs railcar maintenance services at cost for I&M, PSO and SWEPCo. The railcar maintenance revenues in 2016 , 2015 and 2014 were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 1.7 $ 2.0 $ 2.5 PSO 0.6 0.2 0.3 SWEPCo 3.3 2.8 3.3 I&M, PSO and SWEPCo recorded the cost of the railcar maintenance services in Fuel on the balance sheets. I&M Barging, Urea Transloading and Other Services (Applies to APCo and I&M) I&M provides barging, urea transloading and other transportation services to affiliates. Urea is a chemical used to control NO x emissions at certain generation plants in the AEP System. I&M recorded revenues from barging, transloading and other services in Other Revenues – Affiliated on the statements of income. The affiliated companies recorded these costs paid to I&M as fuel expenses or other operation expenses. The amounts of affiliated expenses were: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ 14.8 $ 16.1 $ 22.7 AGR 0.3 4.9 5.2 APCo 36.9 37.7 36.1 KPCo 5.3 4.6 5.0 WPCo 4.8 — — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — 15.5 25.3 Services Provided by AEP River Operations LLC (Applies to I&M) AEP River Operations LLC provided services for barge towing, chartering and general and administrative expenses to I&M. The costs are recorded by I&M as Other Operation expenses. In October 2015, AEP signed a Purchase and Sale Agreement to sell AEP River Operations LLC to a nonaffiliated party. The sale closed in November 2015. For the years ended December 31, 2015 and 2014 , I&M recorded expenses of $19 million and $24 million , respectively, for these activities. Central Machine Shop APCo operates a facility which repairs and rebuilds specialized components for the generation plants across the AEP System. APCo defers the cost of performing these services on the balance sheet and then transfers the cost to the affiliate for reimbursement. The AEP subsidiaries recorded these billings as capital or maintenance expenses depending on the nature of the services received. These billings are recoverable from customers. The following table provides the amounts billed by APCo to the following affiliates: Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1 Affiliate Railcar Agreement (Applies to APCo, I&M, PSO and SWEPCo) Certain AEP subsidiaries have an agreement providing for the use of each other’s leased or owned railcars when available. The agreement specifies that the company using the railcar will be billed, at cost, by the company furnishing the railcar. The AEP subsidiaries recorded these costs or reimbursements as costs or reduction of costs, respectively, in Fuel on the balance sheets and such costs are recoverable from customers. The following tables show the net effect of the railcar agreement on the balance sheets: December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 — OVEC (Applies to APCo, I&M and OPCo) AEP and several nonaffiliated utility companies jointly own OVEC. As of December 31, 2016 , the ownership and investment in OVEC were as follows: December 31, 2016 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4 OVEC’s owners, along with APCo and I&M, are members to an intercompany power agreement. Participants of this agreement are entitled to receive and obligated to pay for all OVEC generating capacity, approximately 2,400 MWs, in proportion to their respective power participation ratios. The aggregate power participation ratio of certain AEP utility subsidiaries, including APCo, I&M and OPCo, is 43.47% . The proceeds from the sale of power by OVEC are designed to be sufficient for OVEC to meet its operating expenses and fixed costs, including outstanding indebtedness, and provide a return on capital. The intercompany power agreement ends in June 2040. AEP and other nonaffiliated owners authorized environmental investments related to their ownership interests. OVEC financed capital expenditures in connection with the engineering and construction of FGD projects and the associated waste disposal landfills at its two generation plants. These environmental projects were funded through debt issuances. As of December 31, 2016, OVEC’s outstanding indebtedness is approximately $1.5 billion . The Registrants’ are responsible for their 43.47% share of OVEC’s outstanding debt. Principal and interest payments related to OVEC’s outstanding indebtedness are disclosed in accordance with the accounting guidance for “Commitments.” See the “Commitments” section of Note 6 . Purchased Power from OVEC The amounts of power purchased by the Registrant Subsidiaries from OVEC for the years ended December 31, 2016 , 2015 and 2014 were: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 88.0 $ 87.2 $ 96.9 I&M 44.0 43.7 48.5 OPCo 111.7 110.8 123.1 The amounts above are included in Purchased Electricity for Resale on the statements of income. Sales and Purchases of Property Certain AEP subsidiaries had affiliated sales and purchases of electric property individually amounting to $100 thousand or more, sales and purchases of meters and transformers, and sales and purchases of transmission property. There were no gains or losses recorded on the transactions. The following tables show the sales and purchases, recorded at net book value, for the years ended December 31, 2016 , 2015 and 2014 : Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2 Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0 The amounts above are recorded in Property, Plant and Equipment on the balance sheets. Intercompany Billings The Registrant Subsidiaries and other AEP subsidiaries perform certain utility services for each other when necessary or practical. The costs of these services are billed on a direct-charge basis, whenever possible, or on reasonable basis of proration for services that benefit multiple companies. The billings for services are made at cost and include no compensation for the use of equity capital.

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP 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, Transource Energy and AEP Renewables. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2016 , 2015 and 2014 were $162 million , $152 million and $151 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 years ended December 31, 2016 , 2015 and 2014 were $101 million , $115 million and $109 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 AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. The securitized bonds totaled $1.2 billion and $1.5 billion as of December 31, 2016 and 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 December 31, 2016 and 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 AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. 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 December 31, 2016 and 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 $62 million and $86 million as of December 31, 2016 and 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 December 31, 2016 and 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 $305 million and $328 million as of December 31, 2016 and 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 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately eight lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2016 , 2015 and 2014 were $28 million , $29 million and $32 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 $45 million and $47 million , in 2016 and 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. AEP Renewables, a wholly-owned subsidiary of Energy Supply, was formed to provide utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations. In the third and fourth quarters of 2016, AEP Renewables acquired Pavant Solar III, LLC and Boulder Solar II, LLC, respectively. AEP Renewables has not received a capital contribution to date from their parent company, but has participated in the AEP corporate borrowing program to fund the aforementioned projects. Management has concluded that AEP Renewables is a VIE and that Energy Supply is the primary beneficiary because Energy Supply has the power to direct the most significant activities of the entity and Energy Supply’s equity interest could potentially be significant. See the tables below for the classification of AEP Renewables’ assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 184.8 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — — 313.0 130.4 Other Noncurrent Assets 10.3 1,149.4 (a) 1.1 5.4 9.0 Total Assets $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 251.9 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 1,064.2 97.3 134.4 11.3 Equity 78.0 18.1 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment — — — 227.2 Other Noncurrent Assets 6.4 1,365.7 (a) 1.9 5.5 Total Assets $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 0.3 1,290.0 83.9 113.0 Equity 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) 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 years ended December 31, 2016 , 2015 and 2014 were $65 million , $93 million and $56 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2016 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 15.7 15.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 91.3 — 82.9 Total Investment in DHLC $ 23.3 $ 114.6 $ 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 were unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at the 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 (ALJ) issued an advisory Initial Decision. Additional briefing was submitted during the fourth quarter of 2015. In January 2017, the FERC issued its order on Initial Decision, adopting in part and rejecting in part the ALJ’s recommendations. The FERC order included (a) a finding that the PATH Project’s abandonment costs were prudently incurred, (b) a finding that the disposition of certain assets was prudent, (c) guidance regarding the future disposition of assets, (d) a reduction of PATH WV’s authorized return on equity (ROE) to 8.11% prospectively only after the date of the order, (e) an adjustment of the amortization period to end December 2017, and (f) a credit for certain amounts that were deemed to be not includable in PATH-WV’s formula rates. In February 2017, the PATH Companies filed a request for rehearing of two adverse rulings in the January 2017 FERC order. The request seeks the FERC to reverse its reduction of the PATH Companies 10.4% ROE for the period after January 19, 2017 and to allow the recovery of certain education and outreach costs disallowed by the order as being required to be recorded in accounts not recoverable under the PATH Companies’ formula rates. The PATH Companies may appeal an adverse order by the FERC once it issues an order on the merits of the PATH Companies’ request for rehearing. In February 2017, the Edison Electric Institute (“EEI”) also filed a request for rehearing recommending reversal of the January 2017 FERC ordered ROE reduction and cost disallowance. The requests for rehearing by the PATH Companies and EEI are currently pending before the FERC. The requests for rehearing do not impact either the timing of the compliance filing required by the order, to be filed in March 2017, or the recovery of costs by the PATH Companies under their formula rates. Depending on the resolution of these proceedings and annual true-ups under their formula rate, the PATH Companies may be required to refund amounts recovered under their formula rates. Management believes its financial statements adequately provide for the outcome of these proceedings. AEP’s investment in PATH-WV was: December 31, 2016 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.3 ) (2.3 ) 2.2 2.2 Total Investment in PATH-WV $ 16.5 $ 16.5 $ 21.0 $ 21.0 As of December 31, 2016 , AEP’s $16.5 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owned 100% of the Lawrenceburg Generating Station, which was sold in January 2017. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2016 , 2015 and 2014 were $229 million , $232 million and $268 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2016 and 2015 was $22 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 . 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 December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 7 for additional information.
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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP 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, Transource Energy and AEP Renewables. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2016 , 2015 and 2014 were $162 million , $152 million and $151 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 years ended December 31, 2016 , 2015 and 2014 were $101 million , $115 million and $109 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 AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. The securitized bonds totaled $1.2 billion and $1.5 billion as of December 31, 2016 and 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 December 31, 2016 and 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 AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. 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 December 31, 2016 and 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 $62 million and $86 million as of December 31, 2016 and 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 December 31, 2016 and 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 $305 million and $328 million as of December 31, 2016 and 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 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately eight lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2016 , 2015 and 2014 were $28 million , $29 million and $32 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 $45 million and $47 million , in 2016 and 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. AEP Renewables, a wholly-owned subsidiary of Energy Supply, was formed to provide utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations. In the third and fourth quarters of 2016, AEP Renewables acquired Pavant Solar III, LLC and Boulder Solar II, LLC, respectively. AEP Renewables has not received a capital contribution to date from their parent company, but has participated in the AEP corporate borrowing program to fund the aforementioned projects. Management has concluded that AEP Renewables is a VIE and that Energy Supply is the primary beneficiary because Energy Supply has the power to direct the most significant activities of the entity and Energy Supply’s equity interest could potentially be significant. See the tables below for the classification of AEP Renewables’ assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 184.8 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — — 313.0 130.4 Other Noncurrent Assets 10.3 1,149.4 (a) 1.1 5.4 9.0 Total Assets $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 251.9 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 1,064.2 97.3 134.4 11.3 Equity 78.0 18.1 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment — — — 227.2 Other Noncurrent Assets 6.4 1,365.7 (a) 1.9 5.5 Total Assets $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 0.3 1,290.0 83.9 113.0 Equity 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) 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 years ended December 31, 2016 , 2015 and 2014 were $65 million , $93 million and $56 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2016 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 15.7 15.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 91.3 — 82.9 Total Investment in DHLC $ 23.3 $ 114.6 $ 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 were unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at the 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 (ALJ) issued an advisory Initial Decision. Additional briefing was submitted during the fourth quarter of 2015. In January 2017, the FERC issued its order on Initial Decision, adopting in part and rejecting in part the ALJ’s recommendations. The FERC order included (a) a finding that the PATH Project’s abandonment costs were prudently incurred, (b) a finding that the disposition of certain assets was prudent, (c) guidance regarding the future disposition of assets, (d) a reduction of PATH WV’s authorized return on equity (ROE) to 8.11% prospectively only after the date of the order, (e) an adjustment of the amortization period to end December 2017, and (f) a credit for certain amounts that were deemed to be not includable in PATH-WV’s formula rates. In February 2017, the PATH Companies filed a request for rehearing of two adverse rulings in the January 2017 FERC order. The request seeks the FERC to reverse its reduction of the PATH Companies 10.4% ROE for the period after January 19, 2017 and to allow the recovery of certain education and outreach costs disallowed by the order as being required to be recorded in accounts not recoverable under the PATH Companies’ formula rates. The PATH Companies may appeal an adverse order by the FERC once it issues an order on the merits of the PATH Companies’ request for rehearing. In February 2017, the Edison Electric Institute (“EEI”) also filed a request for rehearing recommending reversal of the January 2017 FERC ordered ROE reduction and cost disallowance. The requests for rehearing by the PATH Companies and EEI are currently pending before the FERC. The requests for rehearing do not impact either the timing of the compliance filing required by the order, to be filed in March 2017, or the recovery of costs by the PATH Companies under their formula rates. Depending on the resolution of these proceedings and annual true-ups under their formula rate, the PATH Companies may be required to refund amounts recovered under their formula rates. Management believes its financial statements adequately provide for the outcome of these proceedings. AEP’s investment in PATH-WV was: December 31, 2016 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.3 ) (2.3 ) 2.2 2.2 Total Investment in PATH-WV $ 16.5 $ 16.5 $ 21.0 $ 21.0 As of December 31, 2016 , AEP’s $16.5 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owned 100% of the Lawrenceburg Generating Station, which was sold in January 2017. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2016 , 2015 and 2014 were $229 million , $232 million and $268 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2016 and 2015 was $22 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 . 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 December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 7 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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP 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, Transource Energy and AEP Renewables. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2016 , 2015 and 2014 were $162 million , $152 million and $151 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 years ended December 31, 2016 , 2015 and 2014 were $101 million , $115 million and $109 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 AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. The securitized bonds totaled $1.2 billion and $1.5 billion as of December 31, 2016 and 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 December 31, 2016 and 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 AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. 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 December 31, 2016 and 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 $62 million and $86 million as of December 31, 2016 and 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 December 31, 2016 and 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 $305 million and $328 million as of December 31, 2016 and 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 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately eight lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2016 , 2015 and 2014 were $28 million , $29 million and $32 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 $45 million and $47 million , in 2016 and 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. AEP Renewables, a wholly-owned subsidiary of Energy Supply, was formed to provide utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations. In the third and fourth quarters of 2016, AEP Renewables acquired Pavant Solar III, LLC and Boulder Solar II, LLC, respectively. AEP Renewables has not received a capital contribution to date from their parent company, but has participated in the AEP corporate borrowing program to fund the aforementioned projects. Management has concluded that AEP Renewables is a VIE and that Energy Supply is the primary beneficiary because Energy Supply has the power to direct the most significant activities of the entity and Energy Supply’s equity interest could potentially be significant. See the tables below for the classification of AEP Renewables’ assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 184.8 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — — 313.0 130.4 Other Noncurrent Assets 10.3 1,149.4 (a) 1.1 5.4 9.0 Total Assets $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 251.9 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 1,064.2 97.3 134.4 11.3 Equity 78.0 18.1 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment — — — 227.2 Other Noncurrent Assets 6.4 1,365.7 (a) 1.9 5.5 Total Assets $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 0.3 1,290.0 83.9 113.0 Equity 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) 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 years ended December 31, 2016 , 2015 and 2014 were $65 million , $93 million and $56 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2016 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 15.7 15.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 91.3 — 82.9 Total Investment in DHLC $ 23.3 $ 114.6 $ 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 were unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at the 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 (ALJ) issued an advisory Initial Decision. Additional briefing was submitted during the fourth quarter of 2015. In January 2017, the FERC issued its order on Initial Decision, adopting in part and rejecting in part the ALJ’s recommendations. The FERC order included (a) a finding that the PATH Project’s abandonment costs were prudently incurred, (b) a finding that the disposition of certain assets was prudent, (c) guidance regarding the future disposition of assets, (d) a reduction of PATH WV’s authorized return on equity (ROE) to 8.11% prospectively only after the date of the order, (e) an adjustment of the amortization period to end December 2017, and (f) a credit for certain amounts that were deemed to be not includable in PATH-WV’s formula rates. In February 2017, the PATH Companies filed a request for rehearing of two adverse rulings in the January 2017 FERC order. The request seeks the FERC to reverse its reduction of the PATH Companies 10.4% ROE for the period after January 19, 2017 and to allow the recovery of certain education and outreach costs disallowed by the order as being required to be recorded in accounts not recoverable under the PATH Companies’ formula rates. The PATH Companies may appeal an adverse order by the FERC once it issues an order on the merits of the PATH Companies’ request for rehearing. In February 2017, the Edison Electric Institute (“EEI”) also filed a request for rehearing recommending reversal of the January 2017 FERC ordered ROE reduction and cost disallowance. The requests for rehearing by the PATH Companies and EEI are currently pending before the FERC. The requests for rehearing do not impact either the timing of the compliance filing required by the order, to be filed in March 2017, or the recovery of costs by the PATH Companies under their formula rates. Depending on the resolution of these proceedings and annual true-ups under their formula rate, the PATH Companies may be required to refund amounts recovered under their formula rates. Management believes its financial statements adequately provide for the outcome of these proceedings. AEP’s investment in PATH-WV was: December 31, 2016 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.3 ) (2.3 ) 2.2 2.2 Total Investment in PATH-WV $ 16.5 $ 16.5 $ 21.0 $ 21.0 As of December 31, 2016 , AEP’s $16.5 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owned 100% of the Lawrenceburg Generating Station, which was sold in January 2017. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2016 , 2015 and 2014 were $229 million , $232 million and $268 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2016 and 2015 was $22 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 . 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 December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 7 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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP 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, Transource Energy and AEP Renewables. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2016 , 2015 and 2014 were $162 million , $152 million and $151 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 years ended December 31, 2016 , 2015 and 2014 were $101 million , $115 million and $109 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 AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. The securitized bonds totaled $1.2 billion and $1.5 billion as of December 31, 2016 and 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 December 31, 2016 and 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 AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. 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 December 31, 2016 and 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 $62 million and $86 million as of December 31, 2016 and 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 December 31, 2016 and 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 $305 million and $328 million as of December 31, 2016 and 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 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately eight lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2016 , 2015 and 2014 were $28 million , $29 million and $32 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 $45 million and $47 million , in 2016 and 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. AEP Renewables, a wholly-owned subsidiary of Energy Supply, was formed to provide utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations. In the third and fourth quarters of 2016, AEP Renewables acquired Pavant Solar III, LLC and Boulder Solar II, LLC, respectively. AEP Renewables has not received a capital contribution to date from their parent company, but has participated in the AEP corporate borrowing program to fund the aforementioned projects. Management has concluded that AEP Renewables is a VIE and that Energy Supply is the primary beneficiary because Energy Supply has the power to direct the most significant activities of the entity and Energy Supply’s equity interest could potentially be significant. See the tables below for the classification of AEP Renewables’ assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 184.8 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — — 313.0 130.4 Other Noncurrent Assets 10.3 1,149.4 (a) 1.1 5.4 9.0 Total Assets $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 251.9 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 1,064.2 97.3 134.4 11.3 Equity 78.0 18.1 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment — — — 227.2 Other Noncurrent Assets 6.4 1,365.7 (a) 1.9 5.5 Total Assets $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 0.3 1,290.0 83.9 113.0 Equity 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) 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 years ended December 31, 2016 , 2015 and 2014 were $65 million , $93 million and $56 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2016 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 15.7 15.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 91.3 — 82.9 Total Investment in DHLC $ 23.3 $ 114.6 $ 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 were unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at the 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 (ALJ) issued an advisory Initial Decision. Additional briefing was submitted during the fourth quarter of 2015. In January 2017, the FERC issued its order on Initial Decision, adopting in part and rejecting in part the ALJ’s recommendations. The FERC order included (a) a finding that the PATH Project’s abandonment costs were prudently incurred, (b) a finding that the disposition of certain assets was prudent, (c) guidance regarding the future disposition of assets, (d) a reduction of PATH WV’s authorized return on equity (ROE) to 8.11% prospectively only after the date of the order, (e) an adjustment of the amortization period to end December 2017, and (f) a credit for certain amounts that were deemed to be not includable in PATH-WV’s formula rates. In February 2017, the PATH Companies filed a request for rehearing of two adverse rulings in the January 2017 FERC order. The request seeks the FERC to reverse its reduction of the PATH Companies 10.4% ROE for the period after January 19, 2017 and to allow the recovery of certain education and outreach costs disallowed by the order as being required to be recorded in accounts not recoverable under the PATH Companies’ formula rates. The PATH Companies may appeal an adverse order by the FERC once it issues an order on the merits of the PATH Companies’ request for rehearing. In February 2017, the Edison Electric Institute (“EEI”) also filed a request for rehearing recommending reversal of the January 2017 FERC ordered ROE reduction and cost disallowance. The requests for rehearing by the PATH Companies and EEI are currently pending before the FERC. The requests for rehearing do not impact either the timing of the compliance filing required by the order, to be filed in March 2017, or the recovery of costs by the PATH Companies under their formula rates. Depending on the resolution of these proceedings and annual true-ups under their formula rate, the PATH Companies may be required to refund amounts recovered under their formula rates. Management believes its financial statements adequately provide for the outcome of these proceedings. AEP’s investment in PATH-WV was: December 31, 2016 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.3 ) (2.3 ) 2.2 2.2 Total Investment in PATH-WV $ 16.5 $ 16.5 $ 21.0 $ 21.0 As of December 31, 2016 , AEP’s $16.5 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owned 100% of the Lawrenceburg Generating Station, which was sold in January 2017. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2016 , 2015 and 2014 were $229 million , $232 million and $268 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2016 and 2015 was $22 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 . 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 December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 7 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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP 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, Transource Energy and AEP Renewables. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2016 , 2015 and 2014 were $162 million , $152 million and $151 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 years ended December 31, 2016 , 2015 and 2014 were $101 million , $115 million and $109 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 AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. The securitized bonds totaled $1.2 billion and $1.5 billion as of December 31, 2016 and 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 December 31, 2016 and 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 AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. 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 December 31, 2016 and 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 $62 million and $86 million as of December 31, 2016 and 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 December 31, 2016 and 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 $305 million and $328 million as of December 31, 2016 and 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 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately eight lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2016 , 2015 and 2014 were $28 million , $29 million and $32 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 $45 million and $47 million , in 2016 and 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. AEP Renewables, a wholly-owned subsidiary of Energy Supply, was formed to provide utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations. In the third and fourth quarters of 2016, AEP Renewables acquired Pavant Solar III, LLC and Boulder Solar II, LLC, respectively. AEP Renewables has not received a capital contribution to date from their parent company, but has participated in the AEP corporate borrowing program to fund the aforementioned projects. Management has concluded that AEP Renewables is a VIE and that Energy Supply is the primary beneficiary because Energy Supply has the power to direct the most significant activities of the entity and Energy Supply’s equity interest could potentially be significant. See the tables below for the classification of AEP Renewables’ assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 184.8 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — — 313.0 130.4 Other Noncurrent Assets 10.3 1,149.4 (a) 1.1 5.4 9.0 Total Assets $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 251.9 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 1,064.2 97.3 134.4 11.3 Equity 78.0 18.1 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment — — — 227.2 Other Noncurrent Assets 6.4 1,365.7 (a) 1.9 5.5 Total Assets $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 0.3 1,290.0 83.9 113.0 Equity 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) 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 years ended December 31, 2016 , 2015 and 2014 were $65 million , $93 million and $56 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2016 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 15.7 15.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 91.3 — 82.9 Total Investment in DHLC $ 23.3 $ 114.6 $ 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 were unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at the 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 (ALJ) issued an advisory Initial Decision. Additional briefing was submitted during the fourth quarter of 2015. In January 2017, the FERC issued its order on Initial Decision, adopting in part and rejecting in part the ALJ’s recommendations. The FERC order included (a) a finding that the PATH Project’s abandonment costs were prudently incurred, (b) a finding that the disposition of certain assets was prudent, (c) guidance regarding the future disposition of assets, (d) a reduction of PATH WV’s authorized return on equity (ROE) to 8.11% prospectively only after the date of the order, (e) an adjustment of the amortization period to end December 2017, and (f) a credit for certain amounts that were deemed to be not includable in PATH-WV’s formula rates. In February 2017, the PATH Companies filed a request for rehearing of two adverse rulings in the January 2017 FERC order. The request seeks the FERC to reverse its reduction of the PATH Companies 10.4% ROE for the period after January 19, 2017 and to allow the recovery of certain education and outreach costs disallowed by the order as being required to be recorded in accounts not recoverable under the PATH Companies’ formula rates. The PATH Companies may appeal an adverse order by the FERC once it issues an order on the merits of the PATH Companies’ request for rehearing. In February 2017, the Edison Electric Institute (“EEI”) also filed a request for rehearing recommending reversal of the January 2017 FERC ordered ROE reduction and cost disallowance. The requests for rehearing by the PATH Companies and EEI are currently pending before the FERC. The requests for rehearing do not impact either the timing of the compliance filing required by the order, to be filed in March 2017, or the recovery of costs by the PATH Companies under their formula rates. Depending on the resolution of these proceedings and annual true-ups under their formula rate, the PATH Companies may be required to refund amounts recovered under their formula rates. Management believes its financial statements adequately provide for the outcome of these proceedings. AEP’s investment in PATH-WV was: December 31, 2016 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.3 ) (2.3 ) 2.2 2.2 Total Investment in PATH-WV $ 16.5 $ 16.5 $ 21.0 $ 21.0 As of December 31, 2016 , AEP’s $16.5 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owned 100% of the Lawrenceburg Generating Station, which was sold in January 2017. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2016 , 2015 and 2014 were $229 million , $232 million and $268 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2016 and 2015 was $22 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 . 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 December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 7 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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently. AEP 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, Transource Energy and AEP Renewables. In addition, AEP has not provided material financial or other support to any of these entities that was not previously contractually required. AEP holds a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series). Consolidated Variable Interests Entities Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine’s only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo’s total billings from Sabine for the years ended December 31, 2016 , 2015 and 2014 were $162 million , $152 million and $151 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 years ended December 31, 2016 , 2015 and 2014 were $101 million , $115 million and $109 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 AEP Texas is the primary beneficiary of Transition Funding because AEP Texas has the power to direct the most significant activities of the VIE and AEP Texas’ equity interest could potentially be significant. Therefore, AEP Texas is required to consolidate Transition Funding. The securitized bonds totaled $1.2 billion and $1.5 billion as of December 31, 2016 and 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 December 31, 2016 and 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 AEP Texas under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to AEP Texas or any other AEP entity. AEP Texas acts as the servicer for Transition Funding’s securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding’s assets and liabilities on the balance sheets. 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 December 31, 2016 and 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 $62 million and $86 million as of December 31, 2016 and 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 December 31, 2016 and 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 $305 million and $328 million as of December 31, 2016 and 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 14 . AEP’s subsidiaries participate in one protected cell of EIS for approximately eight lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell’s only participant, but allows certain third parties access to this insurance. AEP’s subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on AEP’s control and the structure of the protected cell of EIS, management concluded that AEP is the primary beneficiary of the protected cell and is required to consolidate the protected cell of EIS. The insurance premium expense to the protected cell for the years ended December 31, 2016 , 2015 and 2014 were $28 million , $29 million and $32 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 $45 million and $47 million , in 2016 and 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. AEP Renewables, a wholly-owned subsidiary of Energy Supply, was formed to provide utility scale wind and solar projects whose power output is sold via long-term power purchase agreements to other utilities, cities and corporations. In the third and fourth quarters of 2016, AEP Renewables acquired Pavant Solar III, LLC and Boulder Solar II, LLC, respectively. AEP Renewables has not received a capital contribution to date from their parent company, but has participated in the AEP corporate borrowing program to fund the aforementioned projects. Management has concluded that AEP Renewables is a VIE and that Energy Supply is the primary beneficiary because Energy Supply has the power to direct the most significant activities of the entity and Energy Supply’s equity interest could potentially be significant. See the tables below for the classification of AEP Renewables’ assets and liabilities on the balance sheets. The balances below represent the assets and liabilities of the VIEs that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation. AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 184.8 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — — 313.0 130.4 Other Noncurrent Assets 10.3 1,149.4 (a) 1.1 5.4 9.0 Total Assets $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 251.9 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 1,064.2 97.3 134.4 11.3 Equity 78.0 18.1 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment — — — 227.2 Other Noncurrent Assets 6.4 1,365.7 (a) 1.9 5.5 Total Assets $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 0.3 1,290.0 83.9 113.0 Equity 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) 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 years ended December 31, 2016 , 2015 and 2014 were $65 million , $93 million and $56 million , respectively. SWEPCo is not required to consolidate DHLC as it is not the primary beneficiary, although SWEPCo holds a significant variable interest in DHLC. SWEPCo’s equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on SWEPCo’s balance sheets. SWEPCo’s investment in DHLC was: December 31, 2016 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 15.7 15.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 91.3 — 82.9 Total Investment in DHLC $ 23.3 $ 114.6 $ 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 were unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at the 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 (ALJ) issued an advisory Initial Decision. Additional briefing was submitted during the fourth quarter of 2015. In January 2017, the FERC issued its order on Initial Decision, adopting in part and rejecting in part the ALJ’s recommendations. The FERC order included (a) a finding that the PATH Project’s abandonment costs were prudently incurred, (b) a finding that the disposition of certain assets was prudent, (c) guidance regarding the future disposition of assets, (d) a reduction of PATH WV’s authorized return on equity (ROE) to 8.11% prospectively only after the date of the order, (e) an adjustment of the amortization period to end December 2017, and (f) a credit for certain amounts that were deemed to be not includable in PATH-WV’s formula rates. In February 2017, the PATH Companies filed a request for rehearing of two adverse rulings in the January 2017 FERC order. The request seeks the FERC to reverse its reduction of the PATH Companies 10.4% ROE for the period after January 19, 2017 and to allow the recovery of certain education and outreach costs disallowed by the order as being required to be recorded in accounts not recoverable under the PATH Companies’ formula rates. The PATH Companies may appeal an adverse order by the FERC once it issues an order on the merits of the PATH Companies’ request for rehearing. In February 2017, the Edison Electric Institute (“EEI”) also filed a request for rehearing recommending reversal of the January 2017 FERC ordered ROE reduction and cost disallowance. The requests for rehearing by the PATH Companies and EEI are currently pending before the FERC. The requests for rehearing do not impact either the timing of the compliance filing required by the order, to be filed in March 2017, or the recovery of costs by the PATH Companies under their formula rates. Depending on the resolution of these proceedings and annual true-ups under their formula rate, the PATH Companies may be required to refund amounts recovered under their formula rates. Management believes its financial statements adequately provide for the outcome of these proceedings. AEP’s investment in PATH-WV was: December 31, 2016 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.3 ) (2.3 ) 2.2 2.2 Total Investment in PATH-WV $ 16.5 $ 16.5 $ 21.0 $ 21.0 As of December 31, 2016 , AEP’s $16.5 million investment in PATH-WV was included in Deferred Charges and Other Noncurrent Assets on the balance sheet. If AEP cannot ultimately recover the investment related to PATH-WV, it could reduce future net income and cash flows. AEPSC provides certain managerial and professional services to AEP’s subsidiaries. Parent is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC’s cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC’s cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP. Total AEPSC billings to the Registrant Subsidiaries were as follows: Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 16.4 16.4 AEGCo, a wholly-owned subsidiary of Parent, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owned 100% of the Lawrenceburg Generating Station, which was sold in January 2017. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. Total billings to I&M from AEGCo for the years ended December 31, 2016 , 2015 and 2014 were $229 million , $232 million and $268 million . The carrying amount of I&M’s liabilities associated with AEGCo as of December 31, 2016 and 2015 was $22 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 . 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 December 31, 2016. See “Assets and Liabilities Held for Sale” section of Note 7 for additional information.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, Plant and Equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances as of December 31, 2016 and 2015 : December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 Transmission 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 Distribution 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 Other 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 APCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 35 - 121 3.1% 40 - 121 Transmission 1.5% 15 - 68 1.6% 15 - 68 1.7% 15 - 87 Distribution 3.7% 10 - 57 3.6% 10 - 57 3.5% 13 - 57 Other 6.0% 5 - 55 8.3% 5 - 55 6.9% 24 - 55 I&M 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 59 - 132 2.5% 59 - 132 2.0% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.8% 10 - 70 2.8% 10 - 70 2.8% 15 - 70 Other 8.6% 5 - 45 11.8% 5 - 45 6.1% 14 - 45 OPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.8% 7 - 57 2.7% 7 - 57 Other 5.9% 5 - 50 7.2% 5 - 50 7.0% 7 - 50 PSO 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 1.7% 35 - 70 1.7% 35 - 70 Transmission 2.2% 45 - 100 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.5% 7 - 65 2.4% 30 - 65 Other 6.4% 5 - 84 4.6% 5 - 40 4.1% 5 - 40 SWEPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.2% 50 - 70 2.3% 50 - 70 2.2% 50 - 70 Distribution 2.6% 25 - 65 2.6% 25 - 65 2.7% 25 - 65 Other 6.8% 5 - 51 5.5% 5 - 51 4.8% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of APCo, I&M, OPCo and PSO for 2016 , 2015 and 2014 . AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.3% 43 - 55 Distribution 1.3% 40 50 —% 0 - 0 —% 0 - 0 Other 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2016 and 2015 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.24 billion and $1.18 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2016 and 2015 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.95 billion and $1.80 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in Asset Retirement Obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2016 and 2015 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 . Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Appalachian Power Co [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, Plant and Equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances as of December 31, 2016 and 2015 : December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 Transmission 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 Distribution 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 Other 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 APCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 35 - 121 3.1% 40 - 121 Transmission 1.5% 15 - 68 1.6% 15 - 68 1.7% 15 - 87 Distribution 3.7% 10 - 57 3.6% 10 - 57 3.5% 13 - 57 Other 6.0% 5 - 55 8.3% 5 - 55 6.9% 24 - 55 I&M 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 59 - 132 2.5% 59 - 132 2.0% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.8% 10 - 70 2.8% 10 - 70 2.8% 15 - 70 Other 8.6% 5 - 45 11.8% 5 - 45 6.1% 14 - 45 OPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.8% 7 - 57 2.7% 7 - 57 Other 5.9% 5 - 50 7.2% 5 - 50 7.0% 7 - 50 PSO 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 1.7% 35 - 70 1.7% 35 - 70 Transmission 2.2% 45 - 100 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.5% 7 - 65 2.4% 30 - 65 Other 6.4% 5 - 84 4.6% 5 - 40 4.1% 5 - 40 SWEPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.2% 50 - 70 2.3% 50 - 70 2.2% 50 - 70 Distribution 2.6% 25 - 65 2.6% 25 - 65 2.7% 25 - 65 Other 6.8% 5 - 51 5.5% 5 - 51 4.8% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of APCo, I&M, OPCo and PSO for 2016 , 2015 and 2014 . AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.3% 43 - 55 Distribution 1.3% 40 50 —% 0 - 0 —% 0 - 0 Other 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2016 and 2015 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.24 billion and $1.18 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2016 and 2015 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.95 billion and $1.80 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in Asset Retirement Obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2016 and 2015 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 . Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Indiana Michigan Power Co [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, Plant and Equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances as of December 31, 2016 and 2015 : December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 Transmission 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 Distribution 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 Other 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 APCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 35 - 121 3.1% 40 - 121 Transmission 1.5% 15 - 68 1.6% 15 - 68 1.7% 15 - 87 Distribution 3.7% 10 - 57 3.6% 10 - 57 3.5% 13 - 57 Other 6.0% 5 - 55 8.3% 5 - 55 6.9% 24 - 55 I&M 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 59 - 132 2.5% 59 - 132 2.0% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.8% 10 - 70 2.8% 10 - 70 2.8% 15 - 70 Other 8.6% 5 - 45 11.8% 5 - 45 6.1% 14 - 45 OPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.8% 7 - 57 2.7% 7 - 57 Other 5.9% 5 - 50 7.2% 5 - 50 7.0% 7 - 50 PSO 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 1.7% 35 - 70 1.7% 35 - 70 Transmission 2.2% 45 - 100 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.5% 7 - 65 2.4% 30 - 65 Other 6.4% 5 - 84 4.6% 5 - 40 4.1% 5 - 40 SWEPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.2% 50 - 70 2.3% 50 - 70 2.2% 50 - 70 Distribution 2.6% 25 - 65 2.6% 25 - 65 2.7% 25 - 65 Other 6.8% 5 - 51 5.5% 5 - 51 4.8% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of APCo, I&M, OPCo and PSO for 2016 , 2015 and 2014 . AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.3% 43 - 55 Distribution 1.3% 40 50 —% 0 - 0 —% 0 - 0 Other 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2016 and 2015 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.24 billion and $1.18 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2016 and 2015 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.95 billion and $1.80 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in Asset Retirement Obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2016 and 2015 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 . Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Ohio Power Co [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, Plant and Equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances as of December 31, 2016 and 2015 : December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 Transmission 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 Distribution 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 Other 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 APCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 35 - 121 3.1% 40 - 121 Transmission 1.5% 15 - 68 1.6% 15 - 68 1.7% 15 - 87 Distribution 3.7% 10 - 57 3.6% 10 - 57 3.5% 13 - 57 Other 6.0% 5 - 55 8.3% 5 - 55 6.9% 24 - 55 I&M 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 59 - 132 2.5% 59 - 132 2.0% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.8% 10 - 70 2.8% 10 - 70 2.8% 15 - 70 Other 8.6% 5 - 45 11.8% 5 - 45 6.1% 14 - 45 OPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.8% 7 - 57 2.7% 7 - 57 Other 5.9% 5 - 50 7.2% 5 - 50 7.0% 7 - 50 PSO 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 1.7% 35 - 70 1.7% 35 - 70 Transmission 2.2% 45 - 100 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.5% 7 - 65 2.4% 30 - 65 Other 6.4% 5 - 84 4.6% 5 - 40 4.1% 5 - 40 SWEPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.2% 50 - 70 2.3% 50 - 70 2.2% 50 - 70 Distribution 2.6% 25 - 65 2.6% 25 - 65 2.7% 25 - 65 Other 6.8% 5 - 51 5.5% 5 - 51 4.8% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of APCo, I&M, OPCo and PSO for 2016 , 2015 and 2014 . AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.3% 43 - 55 Distribution 1.3% 40 50 —% 0 - 0 —% 0 - 0 Other 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2016 and 2015 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.24 billion and $1.18 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2016 and 2015 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.95 billion and $1.80 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in Asset Retirement Obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2016 and 2015 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 . Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Public Service Co Of Oklahoma [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, Plant and Equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances as of December 31, 2016 and 2015 : December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 Transmission 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 Distribution 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 Other 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 APCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 35 - 121 3.1% 40 - 121 Transmission 1.5% 15 - 68 1.6% 15 - 68 1.7% 15 - 87 Distribution 3.7% 10 - 57 3.6% 10 - 57 3.5% 13 - 57 Other 6.0% 5 - 55 8.3% 5 - 55 6.9% 24 - 55 I&M 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 59 - 132 2.5% 59 - 132 2.0% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.8% 10 - 70 2.8% 10 - 70 2.8% 15 - 70 Other 8.6% 5 - 45 11.8% 5 - 45 6.1% 14 - 45 OPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.8% 7 - 57 2.7% 7 - 57 Other 5.9% 5 - 50 7.2% 5 - 50 7.0% 7 - 50 PSO 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 1.7% 35 - 70 1.7% 35 - 70 Transmission 2.2% 45 - 100 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.5% 7 - 65 2.4% 30 - 65 Other 6.4% 5 - 84 4.6% 5 - 40 4.1% 5 - 40 SWEPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.2% 50 - 70 2.3% 50 - 70 2.2% 50 - 70 Distribution 2.6% 25 - 65 2.6% 25 - 65 2.7% 25 - 65 Other 6.8% 5 - 51 5.5% 5 - 51 4.8% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of APCo, I&M, OPCo and PSO for 2016 , 2015 and 2014 . AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.3% 43 - 55 Distribution 1.3% 40 50 —% 0 - 0 —% 0 - 0 Other 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2016 and 2015 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.24 billion and $1.18 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2016 and 2015 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.95 billion and $1.80 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in Asset Retirement Obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2016 and 2015 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 . Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Southwestern Electric Power Co [Member]
Property, Plant and Equipment	PROPERTY, PLANT AND EQUIPMENT The disclosures in this note apply to all Registrants unless indicated otherwise. Property, Plant and Equipment is shown functionally on the face of the Registrants’ balance sheets. The following tables include the Registrants’ total plant balances as of December 31, 2016 and 2015 : December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant. Depreciation, Depletion and Amortization The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. The following tables provide total regulated annual composite depreciation rates and depreciable lives for the Registrants: AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 Transmission 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 Distribution 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 Other 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75 APCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 35 - 121 3.1% 40 - 121 Transmission 1.5% 15 - 68 1.6% 15 - 68 1.7% 15 - 87 Distribution 3.7% 10 - 57 3.6% 10 - 57 3.5% 13 - 57 Other 6.0% 5 - 55 8.3% 5 - 55 6.9% 24 - 55 I&M 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 59 - 132 2.5% 59 - 132 2.0% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.8% 10 - 70 2.8% 10 - 70 2.8% 15 - 70 Other 8.6% 5 - 45 11.8% 5 - 45 6.1% 14 - 45 OPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.8% 7 - 57 2.7% 7 - 57 Other 5.9% 5 - 50 7.2% 5 - 50 7.0% 7 - 50 PSO 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 1.7% 35 - 70 1.7% 35 - 70 Transmission 2.2% 45 - 100 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.5% 7 - 65 2.4% 30 - 65 Other 6.4% 5 - 84 4.6% 5 - 40 4.1% 5 - 40 SWEPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.2% 50 - 70 2.3% 50 - 70 2.2% 50 - 70 Distribution 2.6% 25 - 65 2.6% 25 - 65 2.7% 25 - 65 Other 6.8% 5 - 51 5.5% 5 - 51 4.8% 7 - 51 The following table includes the nonregulated annual composite depreciation rate ranges and nonregulated depreciable life ranges for AEP. Depreciation rate ranges and depreciable life ranges are not meaningful for nonregulated property of APCo, I&M, OPCo and PSO for 2016 , 2015 and 2014 . AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.3% 43 - 55 Distribution 1.3% 40 50 —% 0 - 0 —% 0 - 0 Other 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. Asset Retirement Obligations (ARO) The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected. As of December 31, 2016 and 2015 , I&M’s ARO liability for nuclear decommissioning of the Cook Plant was $1.24 billion and $1.18 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M’s balance sheets. As of December 31, 2016 and 2015 , the fair value of I&M’s assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.95 billion and $1.80 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M’s balance sheets. The Registrants recorded an increase in Asset Retirement Obligations in the second quarter of 2015, primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2016 and 2015 aggregate carrying amounts of ARO by Registrant: Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 . Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization The Registrants’ amounts of Allowance for Equity Funds Used During Construction are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 The Registrants’ amounts of allowance for borrowed funds used during construction, including capitalized interest, are summarized in the following table: Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9 Jointly-owned Electric Facilities (Applies to AEP, I&M, PSO and SWEPCo) The Registrants have electric facilities that are jointly-owned with affiliated and non-affiliated companies. Using its own financing, each participating company is obligated to pay its share of the costs of these jointly-owned facilities in the same proportion as its ownership interest. Each Registrant’s proportionate share of the operating costs associated with these facilities is included in its statements of income and the investments and accumulated depreciation are reflected in its balance sheets under Property, Plant and Equipment as follows: Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.

Unaudited Quarterly Financial I

Unaudited Quarterly Financial Information	12 Months Ended
	Dec. 31, 2016
Quarterly Financial Information	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ). AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 (a) Relates to impairments for Merchant Generating Assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ). (d) Relates to sale of AEPRO (see Note 7 ).
Appalachian Power Co [Member]
Quarterly Financial Information	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ). AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 (a) Relates to impairments for Merchant Generating Assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ). (d) Relates to sale of AEPRO (see Note 7 ).
Indiana Michigan Power Co [Member]
Quarterly Financial Information	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ). AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 (a) Relates to impairments for Merchant Generating Assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ). (d) Relates to sale of AEPRO (see Note 7 ).
Ohio Power Co [Member]
Quarterly Financial Information	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ). AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 (a) Relates to impairments for Merchant Generating Assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ). (d) Relates to sale of AEPRO (see Note 7 ).
Public Service Co Of Oklahoma [Member]
Quarterly Financial Information	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ). AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 (a) Relates to impairments for Merchant Generating Assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ). (d) Relates to sale of AEPRO (see Note 7 ).
Southwestern Electric Power Co [Member]
Quarterly Financial Information	UNAUDITED QUARTERLY FINANCIAL INFORMATION The disclosures in this note apply to all Registrants unless indicated otherwise. In management’s opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of the results of operations for interim periods. Quarterly results are not necessarily indicative of a full year’s operations because of various factors. The unaudited quarterly financial information for each Registrant is as follows: Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ). AEP The unaudited quarterly financial information relating to Common Shareholders is as follows: 2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 (a) Relates to impairments for Merchant Generating Assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ). (d) Relates to sale of AEPRO (see Note 7 ).

Goodwill and Other Intangible A

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

Organization and Summary of S29

Organization and Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2016
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Other Temporary Investments	Other Temporary Investments (Applies to AEP) Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and securities available for sale, including marketable securities that management intends to hold for less than one year and investments by its protected cell of EIS. Management classifies investments in marketable securities as available-for-sale or held-to-maturity in accordance with the provisions of “Investments – Debt and Equity Securities” accounting guidance. AEP does not have any investments classified as trading. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI. Held-to-maturity securities reflected in Other Temporary Investments are carried at amortized cost. The cost of securities sold is based on the specific identification or weighted average cost method. In evaluating potential impairment of securities with unrealized losses, management considers, among other criteria, the current fair value compared to cost, the length of time the security’s fair value has been below cost, intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions.
Inventory	Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the effective portion of the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains). See “Accounting for Cash Flow Hedging Strategies” section of Note 10 . Barging Activities (Applies to AEP) AEP River Operations’ revenue, which is presented in Discontinued Operations, was recognized based on percentage of voyage completion. The proportion of freight transportation revenue to be recognized was determined by applying a percentage to the contractual charges for such services. The percentage was determined by dividing the number of miles from the loading point to the position of the barge as of the end of the accounting period by the total miles to the destination specified in the customer’s freight contract. The position of the barge at accounting period end was determined by AEP’s computerized barge tracking system.
Levelization of Nuclear Refueling Outage Costs	Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M) In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Goodwill and Intangible Assets, Policy	Goodwill and Intangible Assets (Applies to AEP) When AEP acquires businesses, management records the fair value of all assets and liabilities, including intangible assets. To the extent that consideration exceeds the fair value of identified assets, goodwill is recorded. Goodwill and intangible assets with indefinite lives are not amortized. Management tests acquired goodwill and other intangible assets with indefinite lives for impairment at least annually at their estimated fair value. Management tests goodwill at the reporting unit level and other intangibles at the asset level. Fair value is the amount at which an asset or liability could be bought or sold in a current transaction between willing parties, that is, other than in a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, management estimates fair value using various internal and external valuation methods. AEP amortizes intangible assets with finite lives over their respective estimated lives to their estimated residual values. AEP also reviews the lives of the amortizable intangibles with finite lives on an annual basis.
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds	Nuclear Trust Funds (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Stock-based Compensation	Stock-Based Compensation Plans As of December 31, 2016 , AEP had performance units and restricted stock units outstanding under the American Electric Power System Long-Term Incentive Plan (LTIP). Upon vesting, performance units are paid in cash and restricted stock units are settled in AEP common shares, except for restricted stock units granted after January 1, 2013 and vesting to executive officers, which are paid in cash. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries. AEP maintains a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan, which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance units granted to employees under the LTIP. AEP career shares are equal in value to shares of AEP common stock and become payable to executives in cash after their service ends. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units become payable in cash to directors after their service ends. Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2016 , 2015 and 2014 is based on awards ultimately expected to vest. Therefore, stock-based compensation expense has been reduced to reflect estimated forfeitures. Accounting guidance for “Compensation - Stock Compensation” requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. For the years ended December 31, 2016 , 2015 and 2014 , compensation expense is included in Net Income for the performance units, career shares, restricted stock units and the non-employee director’s stock units.
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	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Restricted Cash for Securitized Funding	Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds.
Inventory	Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the effective portion of the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Indiana Michigan Power Co [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Inventory	Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the effective portion of the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Levelization of Nuclear Refueling Outage Costs	Levelization of Nuclear Refueling Outage Costs (Applies to AEP and I&M) In accordance with regulatory orders, I&M defers incremental operation and maintenance costs associated with periodic refueling outages at its Cook Plant and amortizes the costs over the period beginning with the month following the start of each unit’s refueling outage and lasting until the end of the month in which the same unit’s next scheduled refueling outage begins.
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Nuclear Trust Funds	Nuclear Trust Funds (Applies to AEP and I&M) Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow I&M to collect through rates to fund future decommissioning and spent nuclear fuel disposal liabilities. By rules or orders, the IURC, the MPSC and the FERC established investment limitations and general risk management guidelines. In general, limitations include: • Acceptable investments (rated investment grade or above when purchased). • Maximum percentage invested in a specific type of investment. • Prohibition of investment in obligations of AEP, I&M or their affiliates. • Withdrawals permitted only for payment of decommissioning costs and trust expenses. I&M maintains trust funds for each regulatory jurisdiction. Regulatory approval is required to withdraw decommissioning funds. These funds are managed by external investment managers who must comply with the guidelines and rules of the applicable regulatory authorities. The trust assets are invested to optimize the net of tax earnings of the trust giving consideration to liquidity, risk, diversification and other prudent investment objectives. I&M records securities held in these trust funds in Spent Nuclear Fuel and Decommissioning Trusts on its balance sheets. I&M records these securities at fair value. I&M classifies securities in the trust funds as available-for-sale due to their long-term purpose. Other-than-temporary impairments for investments in both debt and equity securities are considered realized losses as a result of securities being managed by an external investment management firm. The external investment management firm makes specific investment decisions regarding the debt and equity investments held in these trusts and generally intends to sell debt securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. See the “Nuclear Contingencies” section of Note 6 for additional discussion of nuclear matters.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Ohio Power Co [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Restricted Cash for Securitized Funding	Restricted Cash for Securitized Funding (Applies to APCo and OPCo) Restricted Cash for Securitized Funding includes funds held by trustees primarily for the payment of securitization bonds.
Inventory	Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the effective portion of the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Public Service Co Of Oklahoma [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Inventory	Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the effective portion of the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).
Southwestern Electric Power Co [Member]
Basis of Accounting	ORGANIZATION The Registrants engage in the generation, transmission and distribution of electric power. The Registrant Subsidiaries that conduct most of these activities are regulated by the FERC under the Federal Power Act and the Energy Policy Act of 2005 and maintain accounts in accordance with the FERC and other regulatory guidelines. Most of these companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. AEP provides competitive electric and gas supply for residential, commercial and industrial customers in Ohio, Illinois and other deregulated electricity markets and also provides energy management solutions throughout the United States, including energy efficiency services through its independent retail electric supplier. The Registrants also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States and provide various energy-related services. In addition, operations include barging operations and competitive wind and solar farms. I&M provides barging services to both affiliated and nonaffiliated companies. SWEPCo, through consolidated and nonconsolidated affiliates, conducts lignite mining operations to fuel certain of its generation facilities.
Rates and Service Regulation	Rates and Service Regulation AEP’s public utility subsidiaries’ rates are regulated by the FERC and state regulatory commissions in the eleven state operating territories in which they operate. The FERC also regulates the Registrants’ affiliated transactions, including AEPSC intercompany service billings which are generally at cost, under the 2005 Public Utility Holding Company Act and the Federal Power Act. The FERC also has jurisdiction over the issuances and acquisitions of securities of the public utility subsidiaries, the acquisition or sale of certain utility assets and mergers with another electric utility or holding company. For non-power goods and services, the FERC requires a nonregulated affiliate to bill an affiliated public utility company at no more than market while a public utility must bill the higher of cost or market to a nonregulated affiliate. The state regulatory commissions also regulate certain intercompany transactions under various orders and affiliate statutes. Both the FERC and state regulatory commissions are permitted to review and audit the relevant books and records of companies within a public utility holding company system. The FERC regulates wholesale power markets and wholesale power transactions. The Registrants’ wholesale power transactions are generally market-based. Wholesale power transactions are cost-based regulated when a cost-based contract is negotiated and filed with the FERC or the FERC determines that the Registrants have “market power” in the region where the transaction occurs. Wholesale power supply contracts have been entered into with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. These contracts are generally formula rate mechanisms, which are trued up to actual costs annually. The state regulatory commissions regulate all of the retail distribution operations and rates of the Registrants’ retail public utility subsidiaries on a cost basis. The state regulatory commissions also regulate the retail generation/power supply operations and rates except in Ohio and the ERCOT region of Texas. For generation in Ohio, customers who have not switched to a CRES provider for generation pay market-based auction rates. In addition, all OPCo distribution customers pay for certain deferred generation-related costs through non-bypassable charges. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing is conducted by Texas Retail Electric Providers (REPs). AEP has no active REPs in ERCOT. AEP’s nonregulated subsidiaries enter into short and long-term wholesale transactions to buy or sell capacity, energy and ancillary services in the ERCOT market. In addition, these nonregulated subsidiaries control certain wind and coal-fired generation assets, the power from which is marketed and sold in ERCOT. The FERC also regulates the Registrants’ wholesale transmission operations and rates. Retail transmission rates are based upon the FERC OATT rate when retail rates are unbundled in connection with restructuring. Retail transmission rates are based on formula rates included in the PJM OATT that are cost-based and are unbundled in Ohio for OPCo, in Virginia for APCo and in Michigan for I&M. AEP Texas’ retail transmission rates in Texas are unbundled but the retail transmission rates are regulated, on a cost basis, by the PUCT. Bundled retail transmission rates are regulated, on a cost basis, by the state commissions. Transmission rates for AEP’s seven wholly-owned transmission subsidiaries within the AEP Transmission Holdco segment are based on formula rates included in the applicable RTO’s OATT that are cost-based. In West Virginia, APCo and WPCo provide retail electric service at bundled rates approved by the WVPSC, with rates set on a combined cost-of-service basis. In addition, the FERC regulates the SIA, the Operating Agreement, the Transmission Agreement and the Transmission Coordination Agreement, all of which allocate shared system costs and revenues among the utility subsidiaries that are parties to each agreement. In 2013, the FERC issued orders approving the creation of a PCA and a Power Supply Agreement (PSA), effective January 2014. The PCA is among APCo, I&M and KPCo with AEPSC as the agent to coordinate the participants’ respective power supply resources. Effective May 2015, the PCA was revised and approved by the FERC to include WPCo. Also effective January 2014, the FERC approved the creation of a Bridge Agreement among AGR, APCo, I&M, KPCo and OPCo with AEPSC as the agent. The PSA term ended in May 2015. Effective June 2014, the FERC approved the cancellation of the System Transmission Integration Agreement.
Principles of Consolidation	Principles of Consolidation AEP’s consolidated financial statements include its wholly-owned and majority-owned subsidiaries and VIEs of which AEP is the primary beneficiary. The consolidated financial statements for APCo include the Registrant Subsidiary, its wholly-owned subsidiaries and Appalachian Consumer Rate Relief Funding (a substantially-controlled VIE). The consolidated financial statements for I&M include the Registrant Subsidiary, its wholly-owned subsidiaries and DCC Fuel (substantially-controlled VIEs). The consolidated financial statements for OPCo include the Registrant Subsidiary and Ohio Phase-in-Recovery Funding (a substantially-controlled VIE). The consolidated financial statements for SWEPCo include the Registrant Subsidiary, its wholly-owned subsidiary and Sabine (a substantially-controlled VIE). Intercompany items are eliminated in consolidation. The equity method of accounting is used for equity investments where the Registrants exercise significant influence but do not hold a controlling financial interest. Such investments are initially recorded at cost in Deferred Charges and Other Noncurrent Assets on the balance sheets. The proportionate share of the investee’s equity earnings is included in Equity Earnings of Unconsolidated Subsidiaries on the statements of income. Equity method investments are required to be tested for impairment when it is determined there may be an other-than-temporary loss in value. AEP, I&M, PSO and SWEPCo have ownership interests in generating units that are jointly-owned. The proportionate share of the operating costs associated with such facilities is included in the income statements and the assets and liabilities are reflected on the balance sheets.
Accounting for the Effects of Cost-Based Regulation	Accounting for the Effects of Cost-Based Regulation The Registrants’ financial statements reflect the actions of regulators that result in the recognition of certain revenues and expenses in different time periods than enterprises that are not rate-regulated. In accordance with accounting guidance for “Regulated Operations,” regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates.
Use of Estimates	Use of Estimates The preparation of these financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. These estimates include, but are not limited to, inventory valuation, allowance for doubtful accounts, goodwill, intangible and long-lived asset impairment, unbilled electricity revenue, valuation of long-term energy contracts, the effects of regulation, long-lived asset recovery, storm costs, the effects of contingencies and certain assumptions made in accounting for pension and postretirement benefits. The estimates and assumptions used are based upon management’s evaluation of the relevant facts and circumstances as of the date of the financial statements. Actual results could ultimately differ from those estimates.
Cash and Cash Equivalents	Cash and Cash Equivalents Cash and Cash Equivalents include temporary cash investments with original maturities of three months or less.
Inventory	Inventory Fossil fuel inventories are carried at average cost with the exception of AGR and AEP’s non-regulated ownership share of Oklaunion Plant, which is carried at the lower of average cost or market. Materials and supplies inventories are carried at average cost.
Accounts Receivable	Accounts Receivable Customer accounts receivable primarily include receivables from wholesale and retail energy customers, receivables from energy contract counterparties related to risk management activities and customer receivables primarily related to other revenue-generating activities. Revenue is recognized from electric power sales when power is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, the Registrants accrue and recognize, as Accrued Unbilled Revenues on the balance sheets, an estimate of the revenues for energy delivered since the last billing. AEP Credit factors accounts receivable on a daily basis, excluding receivables from risk management activities, through purchase agreements with I&M, KGPCo, KPCo, OPCo, PSO, SWEPCo and a portion of APCo. Since APCo does not have regulatory authority to sell accounts receivable in its West Virginia regulatory jurisdiction, only a portion of APCo’s accounts receivable are sold to AEP Credit. AEP Credit has a receivables securitization agreement with bank conduits. Under the securitization agreement, AEP Credit receives financing from bank conduits for the interest in the billed and unbilled receivables AEP Credit acquires from affiliated utility subsidiaries.
Allowance for Uncollectible Accounts	Allowance for Uncollectible Accounts Generally, AEP Credit records bad debt expense based upon a 12-month rolling average of bad debt write-offs in proportion to gross accounts receivable purchased from participating AEP subsidiaries. For receivables related to APCo’s West Virginia operations, the bad debt reserve is calculated based on a rolling two-year average write-off in proportion to gross accounts receivable. For customer accounts receivables relating to risk management activities, accounts receivables are reviewed for bad debt reserves at a specific counterparty level basis. For AEP Texas, bad debt reserves are calculated using the specific identification of receivable balances greater than 120 days delinquent, and for those balances less than 120 days where the collection is doubtful. For miscellaneous accounts receivable, bad debt expense is recorded for all amounts outstanding 180 days or greater at 100%, unless specifically identified. Miscellaneous accounts receivable items open less than 180 days may be reserved using specific identification for bad debt reserves.
Concentrations of Credit Risk and Significant Customers	Concentrations of Credit Risk and Significant Customers (Applies to Registrant Subsidiaries) The Registrant Subsidiaries do not have any significant customers that comprise 10% or more of their operating revenues for the year ended December 31, 2016 . The Registrant Subsidiaries monitor credit levels and the financial condition of their customers on a continuing basis to minimize credit risk. The regulatory commissions allow recovery in rates for a reasonable level of bad debt costs. Management believes adequate provisions for credit loss have been made in the accompanying Registrant Subsidiary financial statements.
Emission Allowances	Emission Allowances In regulated jurisdictions, the Registrants record emission allowances at cost, including the annual SO 2 and NO x emission allowance entitlements received at no cost from the Federal EPA. For AEP’s competitive generation business, management records allowances at the lower of cost or market. The Registrants follow the inventory model for these allowances. Allowances expected to be consumed within one year are reported in Materials and Supplies on the balance sheets. Allowances with expected consumption beyond one year are included in Deferred Charges and Other Noncurrent Assets on the balance sheets. The purchases and sales of allowances are reported in the Operating Activities section of the statements of cash flows. These allowances are consumed in the production of energy and are recorded in Fuel and Other Consumables Used for Electric Generation at an average cost on the statements of income. The net margin on sales of emission allowances is included in Vertically Integrated Utilities Revenue on AEP’s statements of income and in Electric Generation, Transmission and Distribution Revenues for nonaffiliated transactions and in Sales to AEP Affiliates for affiliated transactions on Registrant Subsidiaries’ statements of income because of its integral nature to the production process of energy and the Registrants’ revenue optimization strategy for their operations. The net margin on sales of emission allowances affects the determination of deferred fuel or deferred emission allowance costs and the amortization of regulatory assets for certain jurisdictions.
Property, Plant and Equipment and Equity Investments	Property, Plant and Equipment Regulated Electric utility property, plant and equipment for rate-regulated operations are stated at original cost. Additions, major replacements and betterments are added to the plant accounts. Under the group composite method of depreciation, continuous interim routine replacements of items such as boiler tubes, pumps, motors, etc. result in original cost retirements, less salvage, being charged to accumulated depreciation. The group composite method of depreciation assumes that on average, asset components are retired at the end of their useful lives and thus there is no gain or loss. The equipment in each primary electric plant account is identified as a separate group. The depreciation rates that are established take into account the past history of interim capital replacements and the amount of removal cost incurred and salvage received. These rates and the related lives are subject to periodic review. Removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. A regulatory asset balance will occur if actual removal costs incurred exceed accumulated removal costs accrued. The costs of labor, materials and overhead incurred to operate and maintain plant and equipment are included in operating expenses. Long-lived assets are required to be tested for impairment when it is determined that the carrying value of the assets may no longer be recoverable or when the assets meet the held-for-sale criteria under the accounting guidance for “Impairment or Disposal of Long-Lived Assets.” When it becomes probable that an asset in service or an asset under construction will be abandoned and regulatory cost recovery has been disallowed, the cost of that asset shall be removed from plant-in-service or CWIP and charged to expense. The fair value of an asset is the amount at which that asset could be bought or sold in a current transaction between willing parties, as opposed to a forced or liquidation sale. Quoted market prices in active markets are the best evidence of fair value and are used as the basis for the measurement, if available. In the absence of quoted prices for identical or similar assets in active markets, fair value is estimated using various internal and external valuation methods including cash flow analysis and appraisals. Nonregulated Nonregulated operations generally follow the policies of rate-regulated operations listed above but with the following exceptions. Property, plant and equipment of nonregulated operations are stated at original cost (or as adjusted for any applicable impairments) plus the original cost of property acquired or constructed since the acquisition, less disposals. Normal and routine retirements from the plant accounts, net of salvage, are charged to accumulated depreciation for most nonregulated operations under the group composite method of depreciation. A gain or loss would be recorded if the retirement is not considered an interim routine replacement. Removal costs are charged to expense.
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Allowance for Funds Used During Construction and Interest Capitalization For regulated operations, AFUDC represents the estimated cost of borrowed and equity funds used to finance construction projects that is capitalized and recovered through depreciation over the service life of regulated electric utility plant. The Registrants record the equity component of AFUDC in Allowance for Equity Funds Used During Construction and the debt component of AFUDC as a reduction to Interest Expense. For nonregulated operations, including certain generating assets, interest is capitalized during construction in accordance with the accounting guidance for “Capitalization of Interest.”
Fair Value Measurements of Assets and Liabilities	Valuation of Nonderivative Financial Instruments The book values of Cash and Cash Equivalents, Advances to/from Affiliates, Accounts Receivable, Accounts Payable and Short-term Debt approximate fair value because of the short-term maturity of these instruments. The book value of the pre-April 1983 spent nuclear fuel disposal liability approximates the best estimate of its fair value. Fair Value Measurements of Assets and Liabilities The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP’s Board of Directors. AEPSC’s market risk oversight staff independently monitors risk policies, procedures and risk levels and provides members of the Commercial Operations Risk Committee (Regulated Risk Committee) and the Energy Supply Risk Committee (Competitive Risk Committee) various reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Vice Chairman, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For commercial activities, exchange traded derivatives, namely futures contracts, are generally fair valued based on unadjusted quoted prices in active markets and are classified as Level 1. Level 2 inputs primarily consist of OTC broker quotes in moderately active or less active markets, as well as exchange traded contracts where there is insufficient market liquidity to warrant inclusion in Level 1. Management verifies price curves using these broker quotes and classifies these fair values within Level 2 when substantially all of the fair value can be corroborated. Management typically obtains multiple broker quotes, which are nonbinding in nature but are based on recent trades in the marketplace. When multiple broker quotes are obtained, the quoted bid and ask prices are averaged. In certain circumstances, a broker quote may be discarded if it is a clear outlier. Management uses a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, these locations are included within Level 2 as well. Certain OTC and bilaterally executed derivative instruments are executed in less active markets with a lower availability of pricing information. Illiquid transactions, complex structured transactions, FTRs and counterparty credit risk may require nonmarket based inputs. Some of these inputs may be internally developed or extrapolated and utilized to estimate fair value. When such inputs have a significant impact on the measurement of fair value, the instrument is categorized as Level 3. The main driver of contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A portion of the Level 3 instruments have been economically hedged which limits potential earnings volatility. AEP utilizes its trustee’s external pricing service to estimate the fair value of the underlying investments held in the benefit plan and nuclear trusts. AEP’s investment managers review and validate the prices utilized by the trustee to determine fair value. AEP’s management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee’s operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts. Assets in the benefits and nuclear trusts, cash and cash equivalents, other temporary investments and restricted cash for securitized funding are classified using the following methods. Equities are classified as Level 1 holdings if they are actively traded on exchanges. Items classified as Level 1 are investments in money market funds, fixed income and equity mutual funds and domestic equity securities. They are valued based on observable inputs, primarily unadjusted quoted prices in active markets for identical assets. Items classified as Level 2 are primarily investments in individual fixed income securities and cash equivalent funds. Fixed income securities generally do not trade on exchanges and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments. Benefit plan assets included in Level 3 are primarily real estate, infrastructure and private equity investments that are valued using methods requiring judgment including appraisals. The fair value of real estate and infrastructure investments is measured using market capitalization rates, recent sales of comparable investments and independent third-party appraisals. The fair value of private equity investments is measured using cost and purchase multiples, operating results, discounted future cash flows and market based comparable data. Depending on the specific situation, one or multiple approaches are used to determine the valuation of a real estate, infrastructure or private equity investment.
Deferred Fuel Costs	Deferred Fuel Costs The cost of fuel and related emission allowances and emission control chemicals/consumables is charged to Fuel and Other Consumables Used for Electric Generation expense when the fuel is burned or the allowance or consumable is utilized. The cost of fuel also includes the cost of nuclear fuel burned which is computed primarily on the units-of-production method. In regulated jurisdictions with an active FAC, fuel cost over-recoveries (the excess of fuel-related revenues over applicable fuel costs incurred) are generally deferred as current regulatory liabilities and under-recoveries (the excess of applicable fuel costs incurred over fuel-related revenues) are generally deferred as current regulatory assets. Fuel cost over-recovery and under-recovery balances are classified as noncurrent when there is a phase-in plan or the FAC has been suspended. These deferrals are amortized when refunded or when billed to customers in later months with the state regulatory commissions’ review and approval. The amount of an over-recovery or under-recovery can also be affected by actions of the state regulatory commissions. On a routine basis, state regulatory commissions review and/or audit the Registrants’ fuel procurement policies and practices, the fuel cost calculations and FAC deferrals. FAC deferrals are adjusted when costs are no longer probable of recovery or when refunds of fuel reserves are probable. Changes in fuel costs, including purchased power in Kentucky for KPCo, Indiana and Michigan for I&M, in Ohio (through the ESP related to standard service offer load served through auctions) for OPCo, in Arkansas, Louisiana and Texas for SWEPCo, in Oklahoma for PSO, in Virginia and West Virginia for APCo and in West Virginia for WPCo are reflected in rates in a timely manner generally through the FAC. Changes in fuel costs, including purchased power in Ohio (from 2009 through 2011) for OPCo are reflected in rates through FAC phase-in plans. The FAC generally includes some sharing of off-system sales margins. In West Virginia for APCo and WPCo, all of the non-merchant margins from off-system sales are given to customers through the FAC. A portion of margins from off-system sales are given to customers through the FAC and other rate mechanisms in Oklahoma for PSO, Arkansas, Louisiana and Texas for SWEPCo, Kentucky for KPCo, Virginia for APCo and in Indiana and Michigan for I&M. Where the FAC or off-system sales sharing mechanism is capped, frozen or non-existent, changes in fuel costs or sharing of off-system sales impact earnings.
Revenue Recognition	Revenue Recognition Regulatory Accounting The Registrants’ financial statements reflect the actions of regulators that can result in the recognition of revenues and expenses in different time periods than enterprises that are not rate-regulated. Regulatory assets (deferred expenses) and regulatory liabilities (deferred revenue reductions or refunds) are recorded to reflect the economic effects of regulation in the same accounting period by matching expenses with their recovery through regulated revenues and by matching income with its passage to customers in cost-based regulated rates. When regulatory assets are probable of recovery through regulated rates, assets are recorded on the balance sheets. Regulatory assets are tested for probability of recovery at each balance sheet date or whenever new events occur. Examples of new events include the issuance of a regulatory commission order or passage of new legislation. If it is determined that recovery of a regulatory asset is no longer probable, the regulatory asset is written off as a charge against income. Electricity Supply and Delivery Activities The Registrants recognize revenues from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrants recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts. In accordance with the applicable state commission regulatory treatment, PSO and SWEPCo do not record the fuel portion of unbilled revenue. Wholesale transmission revenue is based on FERC approved formula rate filings made for each calendar year using estimated costs. The annual rate filing is compared to actual costs with an over- or under-recovery being trued-up with interest and refunded or recovered in a future year’s rates. Most of the power produced at the generation plants is sold to PJM or SPP. The Registrants also purchase power from PJM and SPP to supply power to customers. Generally, these power sales and purchases are reported on a net basis as revenues on the statements of income. However, purchases of power in excess of sales to PJM or SPP, on an hourly net basis, used to serve retail load are recorded gross as Purchased Electricity for Resale on the statements of income. With the exception of certain dedicated load bilateral power supply contracts, the transactions of AEP’s nonregulated subsidiaries are reported as gross purchases or sales. Physical energy purchases arising from non-derivative contracts are accounted for on a gross basis in Purchased Electricity for Resale on the statements of income. Energy purchases arising from non-trading derivative contracts are recorded based on the transaction’s facts and circumstances. Purchases under non-trading derivatives used to serve accrual based obligations are recorded in Purchased Electricity for Resale on the statements of income. All other non-trading derivative purchases are recorded net in revenues. In general, the Registrants record expenses when purchased electricity is received and when expenses are incurred, with the exception of certain power purchase contracts that are derivatives and accounted for using MTM accounting where generation/supply rates are not cost-based regulated. In jurisdictions where the generation/supply business is subject to cost-based regulation, the unrealized MTM amounts are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Energy Marketing and Risk Management Activities The Registrants engage in power, capacity and, to a lesser extent, natural gas marketing as major power producers and participants in electricity and natural gas markets. The Registrants also engage in power, capacity, coal, natural gas and, to a lesser extent, heating oil, gasoline and other commodity risk management activities focused on markets where the AEP System owns assets and adjacent markets. These activities include the purchase-and-sale of energy under forward contracts at fixed and variable prices. These contracts include physical transactions, exchange-traded futures, and to a lesser extent, OTC swaps and options. Certain energy marketing and risk management transactions are with RTOs. The Registrants recognize revenues and expenses from marketing and risk management transactions that are not derivatives upon delivery of the commodity. The Registrants use MTM accounting for marketing and risk management transactions that are derivatives unless the derivative is designated in a qualifying cash flow hedge relationship or elected normal under the normal purchase normal sale election. The Registrants include realized gains and losses on marketing and risk management transactions in revenues or expense based on the transaction’s facts and circumstances. In certain jurisdictions subject to cost-based regulation, unrealized MTM amounts and some realized gains and losses are deferred as regulatory assets (for losses) and regulatory liabilities (for gains). Unrealized MTM gains and losses are included on the balance sheets as Risk Management Assets or Liabilities as appropriate. Certain qualifying marketing and risk management derivatives transactions are designated as hedges of variability in future cash flows as a result of forecasted transactions (cash flow hedge). In the event the Registrants designate a cash flow hedge, the effective portion of the cash flow hedge’s gain or loss is initially recorded as a component of AOCI. When the forecasted transaction is realized and affects net income, the Registrants subsequently reclassify the gain or loss on the hedge from AOCI into revenues or expenses within the same financial statement line item as the forecasted transaction on their statements of income. In regulated jurisdictions, the ineffective portion is deferred as regulatory assets (for losses) and regulatory liabilities (for gains).
Maintenance	Maintenance The Registrants expense maintenance costs as incurred. If it becomes probable that the Registrants will recover specifically-incurred costs through future rates, a regulatory asset is established to match the expensing of those maintenance costs with their recovery in cost-based regulated revenues. In certain regulated jurisdictions, the Registrants defer costs above the level included in base rates and amortize those deferrals commensurate with recovery through rate riders.
Income Taxes and Investment Tax Credits	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Excise Taxes	Excise Taxes As agents for some state and local governments, the Registrants collect from customers certain excise taxes levied by those state or local governments on customers. The Registrants do not record these taxes as revenue or expense.
Debt	Debt Gains and losses from the reacquisition of debt used to finance regulated electric utility plants are deferred and amortized over the remaining term of the reacquired debt in accordance with their rate-making treatment unless the debt is refinanced. If the reacquired debt associated with the regulated business is refinanced, the reacquisition costs attributable to the portions of the business that are subject to cost-based regulatory accounting are generally deferred and amortized over the term of the replacement debt consistent with its recovery in rates. Operations not subject to cost-based rate regulation report gains and losses on the reacquisition of debt in Interest Expense on the statements of income upon reacquisition. Debt discount or premium and debt issuance expenses are deferred and amortized generally utilizing the straight-line method over the term of the related debt. The straight-line method approximates the effective interest method and is consistent with the treatment in rates for regulated operations. The net amortization expense is included in Interest Expense on the statements of income.
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Investments Held in Trust for Future Liabilities	Investments Held in Trust for Future Liabilities AEP has several trust funds with significant investments intended to provide for future payments of pension and OPEB benefits, nuclear decommissioning and spent nuclear fuel disposal. All of the trust funds’ investments are diversified and managed in compliance with all laws and regulations. The investment strategy for the trust funds is to use a diversified portfolio of investments to achieve an acceptable rate of return while managing the investment risk of the assets relative to the associated liabilities. To minimize investment risk, the trust funds are broadly diversified among classes of assets, investment strategies and investment managers. Management regularly reviews the actual asset allocations and periodically rebalances the investments to targeted allocations when appropriate. Investment policies and guidelines allow investment managers in approved strategies to use financial derivatives to obtain or manage market exposures and to hedge assets and liabilities. The investments are reported at fair value under the “Fair Value Measurements and Disclosures” accounting guidance. Benefit Plans All benefit plan assets are invested in accordance with each plan’s investment policy. The investment policy outlines the investment objectives, strategies and target asset allocations by plan. The investment philosophies for AEP’s benefit plans support the allocation of assets to minimize risks and optimize net returns. Strategies used include: • Maintaining a long-term investment horizon. • Diversifying assets to help control volatility of returns at acceptable levels. • Managing fees, transaction costs and tax liabilities to maximize investment earnings. • Using active management of investments where appropriate risk/return opportunities exist. • Keeping portfolio structure style-neutral to limit volatility compared to applicable benchmarks. • Using alternative asset classes such as real estate and private equity to maximize return and provide additional portfolio diversification. The objective of the investment policy for the pension fund is to maintain the funded status of the plan while providing for growth in the plan assets to offset the growth in the plan liabilities. The current target asset allocations are as follows: Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 % The investment policy for each benefit plan contains various investment limitations. The investment policies establish concentration limits for securities and prohibit the purchase of securities issued by AEP (with the exception of proportionate and immaterial holdings of AEP securities in passive index strategies). However, the investment policies do not preclude the benefit trust funds from receiving contributions in the form of AEP securities, provided that the AEP securities acquired by each plan may not exceed the limitations imposed by law. For equity investments, the concentration limits are as follows: • No security in excess of 5% of all equities. • Cash equivalents must be less than 10% of an investment manager’s equity portfolio. • No individual stock may be more than 10% and 7% for pension and OPEB investments, respectively, of each manager’s equity portfolio. • No investment in excess of 5% of an outstanding class of any company. • No securities may be bought or sold on margin or other use of leverage. For fixed income investments, each investment manager’s portfolio is compared to investment grade, diversified long and intermediate benchmark indices. A portion of the pension assets is invested in real estate funds to provide diversification, add return and hedge against inflation. Real estate properties are illiquid, difficult to value and not actively traded. The pension plan uses external real estate investment managers to invest in commingled funds that hold real estate properties. To mitigate investment risk in the real estate portfolio, commingled real estate funds are used to ensure that holdings are diversified by region, property type and risk classification. Real estate holdings include core, value-added and development risk classifications and some investments in Real Estate Investment Trusts, which are publicly traded real estate securities. A portion of the pension assets is invested in private equity. Private equity investments add return and provide diversification and typically require a long-term time horizon to evaluate investment performance. Private equity is classified as an alternative investment because it is illiquid, difficult to value and not actively traded. The pension plan uses limited partnerships and commingled funds to invest across the private equity investment spectrum. The private equity holdings are with multiple general partners who help monitor the investments and provide investment selection expertise. The holdings are currently comprised of venture capital, buyout and hybrid debt and equity investment instruments. Commingled private equity funds are used to enhance the holdings’ diversity. AEP participates in a securities lending program with BNY Mellon to provide incremental income on idle assets and to provide income to offset custody fees and other administrative expenses. AEP lends securities to borrowers approved by BNY Mellon in exchange for collateral. All loans are collateralized by at least 102% of the loaned asset’s market value and the collateral is invested. The difference between the rebate owed to the borrower and the collateral rate of return determines the earnings on the loaned security. The securities lending program’s objective is providing modest incremental income with a limited increase in risk. Trust owned life insurance (TOLI) underwritten by The Prudential Insurance Company is held in the OPEB plan trusts. The strategy for holding life insurance contracts in the taxable Voluntary Employees’ Beneficiary Association trust is to minimize taxes paid on the asset growth in the trust. Earnings on plan assets are tax-deferred within the TOLI contract and can be tax-free if held until claims are paid. Life insurance proceeds remain in the trust and are used to fund future retiree medical benefit liabilities. With consideration to other investments held in the trust, the cash value of the TOLI contracts is invested in two diversified funds. A portion is invested in a commingled fund with underlying investments in stocks that are actively traded on major international equity exchanges. The other portion of the TOLI cash value is invested in a diversified, commingled fixed income fund with underlying investments in government bonds, corporate bonds and asset-backed securities. Cash and cash equivalents are held in each trust to provide liquidity and meet short-term cash needs. Cash equivalent funds are used to provide diversification and preserve principal. The underlying holdings in the cash funds are investment grade money market instruments including commercial paper, certificates of deposit, treasury bills and other types of investment grade short-term debt securities. The cash funds are valued each business day and provide daily liquidity.
Comprehensive Income (Loss)	Comprehensive Income (Loss) Comprehensive income (loss) is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from nonowner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income (loss) has two components: net income (loss) and other comprehensive income (loss).

Benefit Plans (Policies)

Benefit Plans (Policies)	12 Months Ended
	Dec. 31, 2016
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Appalachian Power Co [Member]
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Indiana Michigan Power Co [Member]
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Ohio Power Co [Member]
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Public Service Co Of Oklahoma [Member]
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.
Southwestern Electric Power Co [Member]
Pension and Other Postretirement Plans	Pension and OPEB Plans AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. The Registrant Subsidiaries are allocated a proportionate share of benefit costs and account for their participation in these plans as multiple-employer plans. AEP sponsors a qualified pension plan and two unfunded nonqualified pension plans. Substantially all AEP employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. AEP also sponsors OPEB plans to provide health and life insurance benefits for retired employees. Due to the Registrant Subsidiaries’ participation in AEP’s benefits plans, the assumptions used by the actuary and the accounting for the plans by each subsidiary are the same. This section details the assumptions that apply to all Registrants and the rate of compensation increase for each Registrant. The Registrants recognize the funded status associated with defined benefit pension and OPEB plans on the balance sheets. Disclosures about the plans are required by the “Compensation – Retirement Benefits” accounting guidance. The Registrants recognize an asset for a plan’s overfunded status or a liability for a plan’s underfunded status, and recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year that are not recognized as a component of net periodic benefit cost. The Registrants record a regulatory asset instead of other comprehensive income for qualifying benefit costs of regulated operations that for ratemaking purposes are deferred for future recovery. The cumulative funded status adjustment is equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction or regulatory asset and deferred gains result in an AOCI equity addition or regulatory liability.

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	12 Months Ended
	Dec. 31, 2016
Derivatives and Hedging	Accounting for Fair Value Hedging Strategies (Applies to AEP) For fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof attributable to a particular risk), the gain or loss on the derivative instrument as well as the offsetting gain or loss on the hedged item associated with the hedged risk impacts Net Income during the period of change. AEP records realized and unrealized gains or losses on interest rate swaps that are designated and qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the statements of income. 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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. 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. 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. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Appalachian Power Co [Member]
Derivatives and Hedging	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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. 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. Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The 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.
Indiana Michigan Power Co [Member]
Derivatives and Hedging	Cross-Default Triggers (Applies to AEP, APCo and I&M) In addition, a majority of non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation that is $50 million or greater. On an ongoing basis, AEP’s risk management organization assesses the appropriateness of these cross-default provisions in the contracts. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” 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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Credit Risk Management 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. 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.
Ohio Power Co [Member]
Derivatives and Hedging	Credit Risk Management limits credit risk in wholesale marketing and trading activities by assessing the creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness on an ongoing basis. Management uses Moody’s, Standard and Poor’s and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis. Master agreements are typically used to facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Collateral requirements in the form of cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. A counterparty is required to post cash or letters of credit in the event exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP’s credit policy. In addition, master agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS AEPSC is agent for and transacts on behalf of AEP subsidiaries, including the Registrant Subsidiaries. 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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The Registrants reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the balance sheets into Interest Expense on the statements of income in those periods in which hedged interest payments occur. Cash Flow Hedging Strategies The Registrants utilize cash flow hedges on certain derivative transactions for the purchase and sale of power (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The Registrants do not hedge all commodity price risk. The Registrants utilize a variety of interest rate derivative transactions in order to manage interest rate risk exposure. The Registrants also utilize interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The Registrants do not hedge all interest rate exposure. At times, the Registrants are exposed to foreign currency exchange rate risks primarily when some fixed assets are purchased from foreign suppliers. In accordance with AEP’s risk management policy, the Registrants may utilize foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency’s appreciation against the dollar. The Registrants do not hedge all foreign currency exposure. ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON THE FINANCIAL STATEMENTS The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the balance sheets at fair value. The fair values of derivative instruments accounted for using MTM accounting or hedge accounting are based on exchange prices and broker quotes. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes, supply and demand market data and assumptions. In order to determine the relevant fair values of the derivative instruments, the Registrants apply valuation adjustments for discounting, liquidity and credit quality. Credit risk is the risk that a counterparty will fail to perform on the contract or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to vary from estimated fair value based upon prevailing market supply and demand conditions. Since energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value risk management contracts. Unforeseen events may cause reasonable price curves to differ from actual price curves throughout a contract’s term and at the time a contract settles. Consequently, there could be significant adverse or favorable effects on future net income and cash flows if market prices are not consistent with management’s estimates of current market consensus for forward prices in the current period. This is particularly true for longer term contracts. Cash flows may vary based on market conditions, margin requirements and the timing of settlement of risk management contracts. According to the accounting guidance for “Derivatives and Hedging,” the Registrants reflect the fair values of derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, the Registrants are required to post or receive cash collateral based on third party contractual agreements and risk profiles. 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.”
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. The 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.” 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. 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.
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. 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 foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrants due to changes in the underlying market prices or rates. Management utilizes derivative instruments to manage these risks. STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES Risk Management Strategies The strategy surrounding the use of derivative instruments primarily focuses on managing risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. The risk management strategies also include the use of derivative instruments for trading purposes which focus on seizing market opportunities to create value driven by expected changes in the market prices of the commodities. To accomplish these objectives, the Registrants primarily employ risk management contracts including physical and financial forward purchase-and-sale contracts and, to a lesser extent, OTC swaps and options. Not all risk management contracts meet the definition of a derivative under the accounting guidance for “Derivatives and Hedging.” Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of this accounting guidance. The Registrants utilize power, capacity, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with the energy business. The Registrants utilize interest rate derivative contracts in order to manage the interest rate exposure associated with the commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. The Registrants also utilize derivative contracts to manage interest rate risk associated with debt financing. For disclosure purposes, these risks are grouped as “Interest Rate.” The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with established risk management policies as approved by the Finance Committee of the Board of Directors. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in the accounting guidance for “Derivatives and Hedging.” Derivative contracts that have been designated as normal purchases or normal sales under that accounting guidance are not subject to MTM accounting treatment and are recognized on the statements of income on an accrual basis. The accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies for and has been designated as part of a hedging relationship and further, on the type of hedging relationship. Depending on the exposure, management designates a hedging instrument as a fair value hedge or a cash flow hedge. For contracts that have not been designated as part of a hedging relationship, the accounting for changes in fair value depends on whether the derivative instrument is held for trading purposes. Unrealized and realized gains and losses on derivative instruments held for trading purposes are included in revenues on a net basis on the statements of income. Unrealized and realized gains and losses on derivative instruments not held for trading purposes are included in revenues or expenses on the statements of income depending on the relevant facts and circumstances. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” 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. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrants initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on the balance sheets until the period the hedged item affects Net Income. The Registrants recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness would be recorded as a regulatory asset (for losses) or a regulatory liability (for gains) if applicable. Realized gains and losses on derivative contracts for the purchase and sale of power designated as cash flow hedges are included in Total Revenues or Purchased Electricity for Resale on the statements of income or in Regulatory Assets or Regulatory Liabilities on the balance sheets, depending on the specific nature of the risk being hedged.

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	12 Months Ended
	Dec. 31, 2016
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Appalachian Power Co [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Indiana Michigan Power Co [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Ohio Power Co [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Public Service Co Of Oklahoma [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.
Southwestern Electric Power Co [Member]
Fair Values of Long-term Debt	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.
Fair Value Assets And Liabilities Measured On Recurring Basis	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques.

Income Taxes (Policies)

Income Taxes (Policies)	12 Months Ended
	Dec. 31, 2016
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Appalachian Power Co [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Indiana Michigan Power Co [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Ohio Power Co [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Public Service Co Of Oklahoma [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.
Southwestern Electric Power Co [Member]
Income Tax Policy	Income Taxes and Investment Tax Credits The Registrants use the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book and tax basis of assets and liabilities which will result in a future tax consequence. When the flow-through method of accounting for temporary differences is reflected in regulated revenues (that is, when deferred taxes are not included in the cost of service for determining regulated rates for electricity), deferred income taxes are recorded and related regulatory assets and liabilities are established to match the regulated revenues and tax expense. Investment tax credits (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. The Registrants account for uncertain tax positions in accordance with the accounting guidance for “Income Taxes.” The Registrants classify interest expense or income related to uncertain tax positions as interest expense or income as appropriate and classify penalties as Other Operation expense. AEP System Tax Allocation Agreement AEP and subsidiaries join in the filing of a consolidated federal income tax return. The allocation of the AEP System’s current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The consolidated net operating loss of the AEP System is allocated to each company in the consolidated group with taxable losses. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the allocation of the consolidated AEP System net operating loss and the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Leases (Policies)

Leases (Policies)	12 Months Ended
	Dec. 31, 2016
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Appalachian Power Co [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Indiana Michigan Power Co [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Ohio Power Co [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Public Service Co Of Oklahoma [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.
Southwestern Electric Power Co [Member]
Lease, Policy [Policy Text Block]	Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Additionally, for regulated operations with capital leases, a capital lease asset and offsetting liability are recorded at the present value of the remaining lease payments for each reporting period. Capital leases for nonregulated property are accounted for as if the assets were owned and financed.

Stock-Based Compensation (Polic

Stock-Based Compensation (Policies)	12 Months Ended
	Dec. 31, 2016
Stock-based Compensation	Stock-Based Compensation Plans As of December 31, 2016 , AEP had performance units and restricted stock units outstanding under the American Electric Power System Long-Term Incentive Plan (LTIP). Upon vesting, performance units are paid in cash and restricted stock units are settled in AEP common shares, except for restricted stock units granted after January 1, 2013 and vesting to executive officers, which are paid in cash. The impact of AEP’s stock-based compensation plans are insignificant to the financial statements of the Registrant Subsidiaries. AEP maintains a variety of tax qualified and nonqualified deferred compensation plans for employees and non-employee directors that include, among other options, an investment in or an investment return equivalent to that of AEP common stock. This includes AEP career shares maintained under the American Electric Power System Stock Ownership Requirement Plan, which facilitates executives in meeting minimum stock ownership requirements assigned to them by the Human Resources Committee of the Board of Directors. AEP career shares are derived from vested performance units granted to employees under the LTIP. AEP career shares are equal in value to shares of AEP common stock and become payable to executives in cash after their service ends. AEP career shares accrue additional dividend shares in an amount equal to dividends paid on AEP common shares at the closing market price on the dividend payments date. AEP compensates their non-employee directors, in part, with stock units under the American Electric Power Company, Inc. Stock Unit Accumulation Plan for Non-Employee Directors. These stock units become payable in cash to directors after their service ends. Management measures and recognizes compensation expense for all share-based payment awards to employees and directors based on estimated fair values. For share-based payment awards with service only vesting conditions, management recognizes compensation expense on a straight-line basis. Stock-based compensation expense recognized on the statements of income for the years ended December 31, 2016 , 2015 and 2014 is based on awards ultimately expected to vest. Therefore, stock-based compensation expense has been reduced to reflect estimated forfeitures. Accounting guidance for “Compensation - Stock Compensation” requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. For the years ended December 31, 2016 , 2015 and 2014 , compensation expense is included in Net Income for the performance units, career shares, restricted stock units and the non-employee director’s stock units.
Stock Based Compensation [Member]
Stock-based Compensation	AEP’s long-term incentive plan available for eligible employees and directors, the Amended and Restated American Electric Power System Long-Term Incentive Plan (the “Prior Plan”), was replaced prospectively for new grants by the American Electric Power System 2015 Long-Term Incentive Plan (the “2015 LTIP”) effective in April 2015. The 2015 LTIP provides for a maximum of 10 million common shares to be available for grant to eligible employees and directors. As of December 31, 2016 , 9,822,644 shares remained available for issuance under the 2015 LTIP plan. No new awards may be granted under the Prior Plan. To the extent the issuance of a share that is subject to an outstanding award under the Prior Plan, the issuance of that share will take place under the Prior Plan. The 2015 LTIP awards may be stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance share units, cash-based awards and other stock-based awards. If a share is issued pursuant to a stock option or a stock appreciation right, it will reduce the aggregate amount authorized under the 2015 LTIP by 0.286 of a share. If a share is issued for any other award that settles in AEP stock, it will reduce the aggregate amount authorized under the 2015 LTIP by one share. Cash settled awards do not reduce the aggregate amount authorized under the 2015 LTIP. The following sections provide further information regarding each type of stock-based compensation award granted by the Human Resources Committee of AEP’s Board of Directors (HR Committee). AEP’s practice prior to August 2016 was to use authorized but unissued shares to fulfill share commitments for stock option exercises and RSU vesting. In August 2016, AEP began also using shares purchased on the open market to fulfill such share commitments. AEP is permitted to use treasury shares, shares acquired in the open market specifically for distribution under the 2015 LTIP and Prior Plan or any combination thereof for this purpose. Management anticipates using a combination of open market purchases and treasury shares for this purpose going forward. The number of new shares issued to fulfill vesting RSUs is generally reduced to offset AEP’s tax withholding obligation. Unrecognized compensation cost related to unvested share-based arrangements will change as the fair value of performance units and AEP career shares is adjusted each period and as forfeitures for all award types are realized. AEP’s unrecognized compensation cost will be recognized over a weighted-average period of 1.37 years .
Performance Units [Member]
Stock-based Compensation	Performance scores and final awards are determined and certified by the HR Committee in accordance with the pre-established performance measures within approximately a month after the end of the performance period. The performance scores for all performance periods were dependent on two equally-weighted performance measures: (a) three -year total shareholder return measured relative to the Standard and Poor’s 500 Electric Utilities Index and (b) three -year cumulative earnings per share measured relative to a target approved by AEP’s Board of Directors. AEP’s performance units are paid out in cash rather than AEP shares and do not reduce the aggregate share authorization. AEP’s performance units have a fair value upon vesting equal to the average closing market price of AEP common stock for the last 20 trading days of the performance period. The number of performance units held at the end of the three year performance period is multiplied by the performance score to determine the actual number of performance units realized. The performance score can range from 0% to 200% and is determined at the end of the performance period based on performance measures, which include both performance and market conditions, established for each grant at the beginning of the performance period by the HR Committee. Certain employees must satisfy stock ownership requirements. If those employees have not met their stock ownership requirements, a portion or all of their performance units are mandatorily deferred as AEP career shares to the extent needed to meet their stock ownership requirement. AEP career shares are a form of non-qualified deferred compensation that has a value equivalent to shares of AEP common stock. AEP career shares are paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and AEP career shares accrue as additional units. Management records compensation cost for performance units over a three-year vesting period. The liability for both the performance units and AEP career shares, recorded in Employee Benefits and Pension Obligations on the balance sheets, is adjusted for changes in value.
Restricted Shares and Restricted Stock Units [Member]
Stock-based Compensation	The HR Committee grants restricted stock units (RSUs), which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments. The RSUs accrue dividends as additional RSUs. The additional RSUs granted as dividends vest on the same date as the underlying RSUs. RSUs are converted into a share of AEP common stock upon vesting, except for AEP’s officers subject to the disclosure requirements set forth in Section 16 of the Securities Exchange Act of 1934, who are paid in cash. In 2014, there were no RSUs granted to Section 16 officers due to a change that deferred granting these and other awards until February 2015. For RSUs paid in shares, compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of RSUs granted by the grant date market closing price. For RSUs paid in cash, compensation cost is recorded over the vesting period and adjusted for changes in fair value until vested. The fair value at vesting is determined by multiplying the number of RSUs vested by the 20 -day average closing price of AEP common stock. The maximum contractual term of outstanding RSUs is approximately 40 months from the grant date.
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Stock-based Compensation	AEP also has a Stock Unit Accumulation Plan for Non-Employee Directors providing each non-employee director with AEP stock units as a substantial portion of their quarterly compensation for their services as a director. The number of stock units provided is based on the closing price of AEP common stock on the last trading day of the quarter for which the stock units were earned. Amounts equivalent to cash dividends on the stock units accrue as additional AEP stock units. The stock units granted to Non-Employee Directors are fully vested upon grant date. Stock units are paid in cash upon termination of board service or up to 10 years later if the participant so elects. Cash payments for stock units are calculated based on the average closing price of AEP common stock for the last 20 trading days prior to the distribution date. After five years of service on the Board of Directors, non-employee directors receive contributions to an AEP stock fund awarded under the Stock Unit Accumulation Plan. Such amounts may be exchanged into other market-based investments that are similar to the investment options available to employees that participate in AEP’s Incentive Compensation Deferral Plan. Management records compensation cost for stock units when the units are awarded and adjusts the liability for changes in value based on the current 20 -day average closing price of AEP common stock on the valuation date.

Variable Interest Entities (Pol

Variable Interest Entities (Policies)	12 Months Ended
	Dec. 31, 2016
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.
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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.
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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.
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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.
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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.
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 variable interest in a VIE. A VIE is a legal entity that possesses any of the following conditions: the entity’s equity at risk is not sufficient to permit the legal entity to finance its activities without additional subordinated financial support, equity owners are unable to direct the activities that most significantly impact the legal entity’s economic performance (or they possess disproportionate voting rights in relation to the economic interest in the legal entity), or the equity owners lack the obligation to absorb the legal entity’s expected losses or the right to receive the legal entity’s expected residual returns. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities”. In determining whether AEP is the primary beneficiary of a VIE, management considers whether AEP has the power to direct the most significant activities of the VIE and is obligated to absorb losses or receive the expected residual returns that are significant to the VIE. Management believes that significant assumptions and judgments were applied consistently.

Property, Plant and Equipment (

Property, Plant and Equipment (Policies)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment	The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
Asset Retirement Obligations	The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Appalachian Power Co [Member]
Property, Plant and Equipment	For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.
Asset Retirement Obligations	The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Indiana Michigan Power Co [Member]
Property, Plant and Equipment	For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.
Asset Retirement Obligations	The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Ohio Power Co [Member]
Property, Plant and Equipment	For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred. The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class.
Asset Retirement Obligations	The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Public Service Co Of Oklahoma [Member]
Property, Plant and Equipment	The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
Asset Retirement Obligations	The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.
Southwestern Electric Power Co [Member]
Property, Plant and Equipment	The Registrants provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class. SWEPCo provides for depreciation, depletion and amortization of coal-mining assets over each asset’s estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. SWEPCo uses either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. SWEPCo includes these costs in fuel expense. For regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization on the balance sheets. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred.
Asset Retirement Obligations	The Registrants record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities. I&M records ARO for the decommissioning of the Cook Plant. The Registrants have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrants plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrants abandon or cease the use of specific easements, which is not expected.

Organization and Summary of S38

Organization and Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2016
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Basic and Diluted EPS Calculations	Years Ended December 31, 2016 2015 2014 (in millions, except per share data) $/share $/share $/share Income from Continuing Operations $ 620.5 $ 1,768.6 $ 1,590.5 Less: Net Income Attributable to Noncontrolling Interests 7.1 5.2 4.2 Earnings Attributable to AEP Common Shareholders from Continuing Operations $ 613.4 $ 1,763.4 $ 1,586.3 Weighted Average Number of Basic Shares Outstanding 491.5 $ 1.25 490.3 $ 3.59 488.6 $ 3.24 Weighted Average Dilutive Effect of Restricted Stock Units 0.2 — 0.3 — 0.3 — Weighted Average Number of Diluted Shares Outstanding 491.7 $ 1.25 490.6 $ 3.59 488.9 $ 3.24
Supplementary Information	2016 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,688.5 $ 387.6 $ 183.9 $ 202.3 $ 122.6 $ 196.6 Amortization of Certain Securitized Assets 254.6 — — 44.3 — — Amortization of Regulatory Assets and Liabilities 19.2 0.9 7.8 (8.0 ) 7.6 (0.1 ) Total Depreciation and Amortization $ 1,962.3 $ 388.5 $ 191.7 $ 238.6 $ 130.2 $ 196.5 2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1 Years Ended December 31, Cash Flow Information 2016 2015 2014 (in millions) Cash Paid for: Interest, Net of Capitalized Amounts $ 848.5 $ 857.2 $ 838.5 Income Taxes 29.5 120.2 117.3 Noncash Investing and Financing Activities: Acquisitions Under Capital Leases 86.1 150.2 135.1 Construction Expenditures Included in Current Liabilities as of December 31, 858.0 741.4 559.3 Construction Expenditures Included in Noncurrent Liabilities as of December 31, — 51.6 — Construction Expenditures Included in Noncurrent Assets as of December 31, — 10.5 — Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31, 2.1 37.9 44.5 Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage 0.7 2.2 3.4 Years Ended December 31, Related Party Transactions 2016 2015 2014 (in millions) AEP Revenues – Other Revenues: OVEC – Barging and Other Transportation Services (a) $ 0.2 $ 0.1 $ 24.0 AEP Expenses – Purchased Electricity for Resale: OVEC 243.7 241.7 268.5 (a) AEP did not ship coal to OVEC in 2016 and 2015.
Appalachian Power Co [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2016 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,688.5 $ 387.6 $ 183.9 $ 202.3 $ 122.6 $ 196.6 Amortization of Certain Securitized Assets 254.6 — — 44.3 — — Amortization of Regulatory Assets and Liabilities 19.2 0.9 7.8 (8.0 ) 7.6 (0.1 ) Total Depreciation and Amortization $ 1,962.3 $ 388.5 $ 191.7 $ 238.6 $ 130.2 $ 196.5 2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1
Indiana Michigan Power Co [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2016 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,688.5 $ 387.6 $ 183.9 $ 202.3 $ 122.6 $ 196.6 Amortization of Certain Securitized Assets 254.6 — — 44.3 — — Amortization of Regulatory Assets and Liabilities 19.2 0.9 7.8 (8.0 ) 7.6 (0.1 ) Total Depreciation and Amortization $ 1,962.3 $ 388.5 $ 191.7 $ 238.6 $ 130.2 $ 196.5 2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1
Ohio Power Co [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2016 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,688.5 $ 387.6 $ 183.9 $ 202.3 $ 122.6 $ 196.6 Amortization of Certain Securitized Assets 254.6 — — 44.3 — — Amortization of Regulatory Assets and Liabilities 19.2 0.9 7.8 (8.0 ) 7.6 (0.1 ) Total Depreciation and Amortization $ 1,962.3 $ 388.5 $ 191.7 $ 238.6 $ 130.2 $ 196.5 2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1
Public Service Co Of Oklahoma [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2016 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,688.5 $ 387.6 $ 183.9 $ 202.3 $ 122.6 $ 196.6 Amortization of Certain Securitized Assets 254.6 — — 44.3 — — Amortization of Regulatory Assets and Liabilities 19.2 0.9 7.8 (8.0 ) 7.6 (0.1 ) Total Depreciation and Amortization $ 1,962.3 $ 388.5 $ 191.7 $ 238.6 $ 130.2 $ 196.5 2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1
Southwestern Electric Power Co [Member]
Target Asset Allocations	Pension Plan Assets Target Equity 25 % Fixed Income 59 % Other Investments 15 % Cash and Cash Equivalents 1 % OPEB Plans Assets Target Equity 65 % Fixed Income 33 % Cash and Cash Equivalents 2 %
Supplementary Information	2016 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,688.5 $ 387.6 $ 183.9 $ 202.3 $ 122.6 $ 196.6 Amortization of Certain Securitized Assets 254.6 — — 44.3 — — Amortization of Regulatory Assets and Liabilities 19.2 0.9 7.8 (8.0 ) 7.6 (0.1 ) Total Depreciation and Amortization $ 1,962.3 $ 388.5 $ 191.7 $ 238.6 $ 130.2 $ 196.5 2015 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,674.3 $ 385.6 $ 193.5 $ 184.4 $ 108.6 $ 190.7 Amortization of Certain Securitized Assets 318.9 — — 43.3 — — Amortization of Regulatory Assets and Liabilities 16.5 3.2 4.9 (10.2 ) 8.9 1.3 Total Depreciation and Amortization $ 2,009.7 $ 388.8 $ 198.4 $ 217.5 $ 117.5 $ 192.0 2014 Depreciation and Amortization AEP APCo I&M OPCo PSO SWEPCo (in millions) Depreciation and Amortization of Property, Plant and Equipment $ 1,573.7 $ 383.3 $ 199.3 $ 188.3 $ 99.7 $ 183.2 Amortization of Certain Securitized Assets 310.4 — — 43.5 — — Amortization of Regulatory Assets and Liabilities 13.5 17.6 0.9 (18.1 ) 1.3 1.9 Total Depreciation and Amortization $ 1,897.6 $ 400.9 $ 200.2 $ 213.7 $ 101.0 $ 185.1

Comprehensive Income (Tables)

Comprehensive Income (Tables)	12 Months Ended
	Dec. 31, 2016
Changes in Accumulated Other Comprehensive Income (Loss) by Component	AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) Change in Fair Value Recognized in AOCI (14.6 ) — 1.3 — (14.7 ) (28.0 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (21.4 ) — — — — (21.4 ) Purchased Electricity for Resale 16.4 — — — — 16.4 Interest Expense — 2.4 — — — 2.4 Amortization of Prior Service Cost (Credit) — — — (19.4 ) — (19.4 ) Amortization of Actuarial (Gains)/Losses — — — 20.3 — 20.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (5.0 ) 2.4 — 0.9 — (1.7 ) Income Tax (Expense) Credit (1.7 ) 0.9 — 0.3 — (0.5 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (3.3 ) 1.5 — 0.6 — (1.2 ) Net Current Period Other Comprehensive Income (Loss) (17.9 ) 1.5 1.3 0.6 (14.7 ) (29.2 ) Balance in AOCI as of December 31, 2016 $ (23.1 ) $ (15.7 ) $ 8.4 $ 140.5 $ (266.4 ) $ (156.3 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) Change in Fair Value Recognized in AOCI 5.6 — (0.6 ) — (25.7 ) (20.7 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues (48.1 ) — — — — (48.1 ) Purchased Electricity for Resale 29.1 — — — — 29.1 Interest Expense — 2.9 — — — 2.9 Amortization of Prior Service Cost (Credit) — — — (19.5 ) — (19.5 ) Amortization of Actuarial (Gains)/Losses — — — 21.3 — 21.3 Reclassifications from AOCI, before Income Tax (Expense) Credit (19.0 ) 2.9 — 1.8 — (14.3 ) Income Tax (Expense) Credit (6.6 ) 1.0 — 0.6 — (5.0 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (12.4 ) 1.9 — 1.2 — (9.3 ) Net Current Period Other Comprehensive Income (Loss) (6.8 ) 1.9 (0.6 ) 1.2 (25.7 ) (30.0 ) Balance in AOCI as of Pension and OPEB Adjustment Related to Mitchell Plant — — — — 6.0 6.0 Balance in AOCI as of December 31, 2015 $ (5.2 ) $ (17.2 ) $ 7.1 $ 139.9 $ (251.7 ) $ (127.1 ) AEP Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Securities Available for Sale Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.2 $ (23.0 ) $ 6.8 $ 133.9 $ (233.1 ) $ (115.2 ) Change in Fair Value Recognized in AOCI (9.8 ) — 0.9 — 1.1 (7.8 ) Amount of (Gain) Loss Reclassified from AOCI Generation & Marketing Revenues 59.1 — — — — 59.1 Purchased Electricity for Resale (39.1 ) — — — — (39.1 ) Regulatory Assets/(Liabilities), Net (a) (2.8 ) — — — — (2.8 ) Interest Expense — 6.1 — — — 6.1 Amortization of Prior Service Cost (Credit) — — — (20.6 ) — (20.6 ) Amortization of Actuarial (Gains)/Losses — — — 28.0 — 28.0 Reclassifications from AOCI, before Income Tax (Expense) Credit 17.2 6.1 — 7.4 — 30.7 Income Tax (Expense) Credit 6.0 2.2 — 2.6 — 10.8 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 11.2 3.9 — 4.8 — 19.9 Net Current Period Other Comprehensive Income 1.4 3.9 0.9 4.8 1.1 12.1 Balance in AOCI as of December 31, 2014 $ 1.6 $ (19.1 ) $ 7.7 $ 138.7 $ (232.0 ) $ (103.1 ) (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Appalachian Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.1 ) — — (1.1 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.0 — 3.0 Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.1 ) (2.1 ) — (3.2 ) Income Tax (Expense) Credit — (0.4 ) (0.7 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.7 ) (1.4 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.7 ) (1.4 ) (3.5 ) (5.6 ) Balance in AOCI as of December 31, 2016 $ — $ 2.9 $ 16.0 $ (27.3 ) $ (8.4 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 Change in Fair Value Recognized in AOCI — — — (5.7 ) (5.7 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (0.4 ) — — (0.4 ) Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 2.3 — 2.3 Reclassifications from AOCI, before Income Tax (Expense) Credit — (0.4 ) (2.8 ) — (3.2 ) Income Tax (Expense) Credit — (0.1 ) (1.0 ) — (1.1 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (0.3 ) (1.8 ) — (2.1 ) Net Current Period Other Comprehensive Loss — (0.3 ) (1.8 ) (5.7 ) (7.8 ) Balance in AOCI as of December 31, 2015 $ — $ 3.6 $ 17.4 $ (23.8 ) $ (2.8 ) APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 3.1 $ 20.5 $ (20.8 ) $ 2.9 Change in Fair Value Recognized in AOCI 1.7 — — 2.7 4.4 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.5 ) — — — (0.5 ) Regulatory Assets/(Liabilities), Net (a) (2.2 ) — — — (2.2 ) Interest Expense — 1.2 — — 1.2 Amortization of Prior Service Cost (Credit) — — (5.1 ) — (5.1 ) Amortization of Actuarial (Gains)/Losses — — 3.1 — 3.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (2.7 ) 1.2 (2.0 ) — (3.5 ) Income Tax (Expense) Credit (0.9 ) 0.4 (0.7 ) — (1.2 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.8 ) 0.8 (1.3 ) — (2.3 ) Net Current Period Other Comprehensive Income (Loss) (0.1 ) 0.8 (1.3 ) 2.7 2.1 Balance in AOCI as of December 31, 2014 $ — $ 3.9 $ 19.2 $ (18.1 ) $ 5.0 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Indiana Michigan Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) Change in Fair Value Recognized in AOCI — — — (0.8 ) (0.8 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.0 — — 2.0 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 0.8 — 0.8 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.0 — — 2.0 Income Tax (Expense) Credit — 0.7 — — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.3 — — 1.3 Net Current Period Other Comprehensive Income (Loss) — 1.3 — (0.8 ) 0.5 Balance in AOCI as of December 31, 2016 $ — $ (12.0 ) $ 5.1 $ (9.3 ) $ (16.2 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 ) Change in Fair Value Recognized in AOCI — — — (3.5 ) (3.5 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 1.7 — — 1.7 Amortization of Prior Service Cost (Credit) — — (0.9 ) — (0.9 ) Amortization of Actuarial (Gains)/Losses — — 0.9 — 0.9 Reclassifications from AOCI, before Income Tax (Expense) Credit — 1.7 — — 1.7 Income Tax (Expense) Credit — 0.6 — — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.1 — — 1.1 Net Current Period Other Comprehensive Income (Loss) — 1.1 — (3.5 ) (2.4 ) Balance in AOCI as of December 31, 2015 $ — $ (13.3 ) $ 5.1 $ (8.5 ) $ (16.7 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ (16.0 ) $ 4.9 $ (4.5 ) $ (15.5 ) Change in Fair Value Recognized in AOCI 1.1 — — (0.5 ) 0.6 Amount of (Gain) Loss Reclassified from AOCI Purchased Electricity for Resale (0.8 ) — — — (0.8 ) Regulatory Assets/(Liabilities), Net (a) (1.0 ) — — — (1.0 ) Interest Expense — 2.4 — — 2.4 Amortization of Prior Service Cost (Credit) — — (0.8 ) — (0.8 ) Amortization of Actuarial (Gains)/Losses — — 1.1 — 1.1 Reclassifications from AOCI, before Income Tax (Expense) Credit (1.8 ) 2.4 0.3 — 0.9 Income Tax (Expense) Credit (0.6 ) 0.8 0.1 — 0.3 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (1.2 ) 1.6 0.2 — 0.6 Net Current Period Other Comprehensive Income (Loss) (0.1 ) 1.6 0.2 (0.5 ) 1.2 Balance in AOCI as of December 31, 2014 $ — $ (14.4 ) $ 5.1 $ (5.0 ) $ (14.3 )
Ohio Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets. OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 4.3 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.9 ) (1.9 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (1.9 ) (1.9 ) Income Tax (Expense) Credit — (0.6 ) (0.6 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) (1.3 ) Balance in AOCI as of December 31, 2016 $ — $ 3.0 $ 3.0 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (2.0 ) — — (2.0 ) Reclassifications from AOCI, before Income Tax (Expense) Credit — (2.0 ) — — (2.0 ) Income Tax (Expense) Credit — (0.7 ) — — (0.7 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit — (1.3 ) — — (1.3 ) Net Current Period Other Comprehensive Loss — (1.3 ) — — (1.3 ) Balance in AOCI as of December 31, 2015 $ — $ 4.3 $ 58.4 $ (58.4 ) $ 4.3 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 7.0 $ 58.4 $ (58.4 ) $ 7.1 Change in Fair Value Recognized in AOCI — — — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.2 ) — — — (0.2 ) Interest Expense — (2.1 ) — — (2.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.2 ) (2.1 ) — — (2.3 ) Income Tax (Expense) Credit (0.1 ) (0.7 ) — — (0.8 ) 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 December 31, 2014 $ — $ 5.6 $ 58.4 $ (58.4 ) $ 5.6
Public Service Co Of Oklahoma [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2016 $ — $ 3.4 $ 3.4 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Interest Expense — (1.2 ) (1.2 ) 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 Loss — (0.8 ) (0.8 ) Balance in AOCI as of December 31, 2015 $ — $ 4.2 $ 4.2 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Commodity Interest Rate Total (in millions) Balance in AOCI as of December 31, 2013 $ 0.1 $ 5.7 $ 5.8 Change in Fair Value Recognized in AOCI — — — Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — (0.1 ) Interest Expense — (1.1 ) (1.1 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) (1.1 ) (1.2 ) Income Tax (Expense) Credit — (0.4 ) (0.4 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (0.1 ) (0.7 ) (0.8 ) Net Current Period Other Comprehensive Loss (0.1 ) (0.7 ) (0.8 ) Balance in AOCI as of December 31, 2014 $ — $ 5.0 $ 5.0 (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Southwestern Electric Power Co [Member]
Changes in Accumulated Other Comprehensive Income (Loss) by Component	SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2016 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) Change in Fair Value Recognized in AOCI — — — (1.0 ) (1.0 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 2.7 — — 2.7 Amortization of Prior Service Cost (Credit) — — (1.8 ) — (1.8 ) Amortization of Actuarial (Gains)/Losses — — 0.7 — 0.7 Reclassifications from AOCI, before Income Tax (Expense) Credit — 2.7 (1.1 ) — 1.6 Income Tax (Expense) Credit — 1.0 (0.4 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 1.7 (0.7 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 1.7 (0.7 ) (1.0 ) — Balance in AOCI as of December 31, 2016 $ — $ (7.4 ) $ 1.9 $ (3.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2015 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) Change in Fair Value Recognized in AOCI — — — (2.9 ) (2.9 ) Amount of (Gain) Loss Reclassified from AOCI Interest Expense — 3.1 — — 3.1 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.4 — 0.4 Reclassifications from AOCI, before Income Tax (Expense) Credit — 3.1 (1.5 ) — 1.6 Income Tax (Expense) Credit — 1.1 (0.5 ) — 0.6 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.0 (1.0 ) — 1.0 Net Current Period Other Comprehensive Income (Loss) — 2.0 (1.0 ) (2.9 ) (1.9 ) Balance in AOCI as of December 31, 2015 $ — $ (9.1 ) $ 2.6 $ (2.9 ) $ (9.4 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Year Ended December 31, 2014 Cash Flow Hedges Pension and OPEB Commodity Interest Rate Amortization of Deferred Costs Changes in Funded Status Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (13.3 ) $ 4.5 $ 0.3 $ (8.5 ) Change in Fair Value Recognized in AOCI — — — (0.3 ) (0.3 ) Amount of (Gain) Loss Reclassified from AOCI Regulatory Assets/(Liabilities), Net (a) (0.1 ) — — — (0.1 ) Interest Expense — 3.5 — — 3.5 Amortization of Prior Service Cost (Credit) — — (1.9 ) — (1.9 ) Amortization of Actuarial (Gains)/Losses — — 0.5 — 0.5 Reclassifications from AOCI, before Income Tax (Expense) Credit (0.1 ) 3.5 (1.4 ) — 2.0 Income Tax (Expense) Credit (0.1 ) 1.3 (0.5 ) — 0.7 Reclassifications from AOCI, Net of Income Tax (Expense) Credit — 2.2 (0.9 ) — 1.3 Net Current Period Other Comprehensive Income (Loss) — 2.2 (0.9 ) (0.3 ) 1.0 Balance in AOCI as of December 31, 2014 $ — $ (11.1 ) $ 3.6 $ — $ (7.5 ) (a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Rate Matters Rate Matters (Tabl

Rate Matters Rate Matters (Tables)	12 Months Ended
	Dec. 31, 2016
Schedule of Income Statement Impact Related to RSR Expenses [Table Text Block]	AEP (in millions) Fuel and Other Consumables Used for Electric Generation $ (19.0 ) Purchased Electricity for Resale (19.9 ) Other Operation (15.7 ) Depreciation and Amortization (42.1 ) Total Decrease in RSR Expenses $ (96.7 )

Effects of Regulation (Tables)

Effects of Regulation (Tables)	12 Months Ended
	Dec. 31, 2016
Regulatory Assets	AEP December 31, Remaining Recovery Period 2016 2015 Current Regulatory Assets (in millions) Under-recovered Fuel Costs - earns a return $ 61.4 $ 38.9 1 year Under-recovered Fuel Costs - does not earn a return 95.2 76.3 1 year Total Current Regulatory Assets $ 156.6 $ 115.2 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 159.9 $ — Ohio Capacity Deferral 96.7 — Storm Related Costs 25.1 24.2 Plant Retirement Costs - Materials and Supplies 9.1 20.9 Other Regulatory Assets Pending Final Regulatory Approval 1.3 — Regulatory Assets Currently Not Earning a Return Cook Plant Uprate Project 36.3 — Plant Retirement Costs - Asset Retirement Obligation Costs 29.6 59.8 Storm Related Costs 25.9 18.2 Environmental Control Projects 24.1 — Cook Plant Turbine 12.8 9.7 Peak Demand Reduction/Energy Efficiency 0.2 13.1 Other Regulatory Assets Pending Final Regulatory Approval 29.1 22.0 Total Regulatory Assets Pending Final Regulatory Approval (b) 450.1 167.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 550.6 539.3 28 years Ohio Phase-In Recovery Rider 218.9 304.5 2 years Ohio Capacity Deferral 201.9 358.7 2 years Meter Replacement Costs 99.9 90.4 11 years Ohio Distribution Decoupling 41.8 37.5 2 years Advanced Metering System 20.9 3.6 4 years Basic Transmission Cost Rider 19.9 — 2 years West Virginia Delayed Customer Billing 19.5 — 2 years Asset Removal Costs 18.7 38.1 (a) Mitchell Plant Transfer 18.5 19.3 24 years Plant Retirement Costs - Asset Retirement Obligation Costs 18.3 7.6 24 years Storm Related Costs 15.3 8.8 3 years Red Rock Generating Facility 9.1 9.3 40 years Ohio Transmission Cost Recovery Rider — 12.3 Other Regulatory Assets Approved for Recovery 27.6 25.5 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (c) 1,575.0 1,385.3 62 years Pension and OPEB Funded Status 1,516.2 1,410.5 12 years Unamortized Loss on Reacquired Debt 137.8 148.7 29 years Unrealized Loss on Forward Commitments 119.1 10.7 16 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Storm Related Costs 58.7 94.6 4 years Peak Demand Reduction/Energy Efficiency 49.9 33.3 5 years Plant Retirement Costs - Asset Retirement Obligation Costs 48.9 58.0 24 years Postemployment Benefits 39.1 42.6 5 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Medicare Subsidy 37.2 41.8 8 years Vegetation Management 31.4 36.9 5 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years OVEC Purchased Power 22.1 — 2 years United Mine Workers of America Pension Withdrawal 20.2 14.4 6 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year SPP Base Plan Fees 10.7 — 2 years Carbon Capture and Storage Product Validation Facility 9.1 11.7 4 years IGCC Pre-Construction Costs 8.6 10.9 24 years Transmission Cost Recovery Factor 5.3 9.9 1 year Distribution Investment Rider 2.0 12.3 2 years Other Regulatory Assets Approved for Recovery 52.5 77.8 various Total Regulatory Assets Approved for Recovery 5,175.4 4,972.4 Total Noncurrent Regulatory Assets $ 5,625.5 $ 5,140.3 (a) As a regulated entity, removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. As of December 31, 2016 , KPCo’s accumulated actual removal cost incurred exceeded accumulated removal cost accrued, creating an asset balance. As a result, the balance was reclassified to a regulatory asset. Within the next two years, KPCo’s removal costs accrued are expected to exceed removal costs incurred resulting in a regulatory liability. (b) As of December 31, 2016, APCo has deferred a total of $91 million as charges to accumulated depreciation related to certain plant retirements in 2015. APCo intends to address the need for depreciation rate increases in a subsequent base rate cases. (c) Includes $320 million and $288 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates.
Regulatory Liabilities	AEP December 31, Remaining 2016 2015 Refund Period Current Regulatory Liabilities (in millions) Over-recovered Fuel Costs - pays a return $ 3.8 $ 84.8 1 year Over-recovered Fuel Costs - does not pay a return 4.2 29.1 1 year Total Current Regulatory Liabilities $ 8.0 $ 113.9 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.8 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.8 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) 2,627.5 2,656.5 (b) Advanced Metering Infrastructure Surcharge 17.0 21.2 4 years Louisiana Refundable Construction Financing Costs 16.2 37.4 2 years Deferred Investment Tax Credits 12.6 14.7 42 years Excess Earnings 10.0 10.6 37 years Other Regulatory Liabilities Approved for Payment 1.6 20.5 various Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Deferred Investment Tax Credits 132.9 113.3 46 years Spent Nuclear Fuel 44.2 43.4 (c) Transition Charges 40.5 46.5 11 years Peak Demand Reduction/Energy Efficiency 34.0 5.3 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Advanced Metering Costs 11.5 11.4 1 year Unrealized Gain on Forward Commitments 6.2 33.8 2 years Deferred Wind Power Costs 2.1 11.8 1 year Other Regulatory Liabilities Approved for Payment 29.4 24.4 various Total Regulatory Liabilities Approved for Payment 3,750.5 3,695.3 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 3,751.3 $ 3,736.1 (a) As of December 31, 2016, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. APCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 6.2 $ 27.3 1 year Under-recovered Fuel Costs - does not earn a return 62.2 59.6 1 year Total Current Regulatory Assets $ 68.4 $ 86.9 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ 9.1 $ 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 (a) 39.3 57.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant - West Virginia 85.4 86.5 27 years West Virginia Delayed Customer Billing 18.1 — 2 years Storm Related Costs - Virginia 4.6 8.8 2 years RTO Formation/Integration Costs 1.6 2.1 3 years Other Regulatory Assets Approved for Recovery 0.6 — various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (b) 463.5 441.7 26 years Pension and OPEB Funded Status 221.4 217.6 12 years Unamortized Loss on Reacquired Debt 97.2 101.5 29 years Storm Related Costs - West Virginia 47.8 63.5 4 years Virginia Transmission Rate Adjustment Clause 38.7 74.6 2 years Vegetation Management Program - West Virginia 31.4 31.2 5 years Peak Demand Reduction/Energy Efficiency 19.2 3.5 4 years Postemployment Benefits 17.4 19.6 5 years Carbon Capture and Storage Product Validation Facility - West Virginia, FERC 9.1 11.7 4 years IGCC Pre-Construction Costs - West Virginia, FERC 7.4 9.6 4 years Virginia Generation Rate Adjustment Clause 6.5 5.2 2 years Medicare Subsidy - West Virginia, FERC 4.7 5.3 8 years Uncollected Accounts - West Virginia 2.7 3.5 4 years Deferred Restructuring Costs - West Virginia 2.5 4.5 2 years Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC 1.0 1.2 6 years Asset Retirement Obligation 0.6 2.4 1 year Transmission Agreement Phase-In - West Virginia — 1.7 Other Regulatory Assets Approved for Recovery 0.4 1.2 various Total Regulatory Assets Approved for Recovery 1,081.8 1,096.9 Total Noncurrent Regulatory Assets $ 1,121.1 $ 1,154.2
Appalachian Power Co [Member]
Regulatory Assets	a) As of December 31, 2016, APCo has also deferred $91 million as a charge to accumulated depreciation related to the net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements and not abandonments. APCo intends to address the need for an increase in its Virginia depreciation rates in March 2020, as part of its 2018-2019 Virginia biennial filing. (b) Includes $64 million and $59 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. APCo December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 616.9 $ 612.9 (a) Deferred Investment Tax Credits 0.9 1.0 42 years Regulatory Liabilities Currently Not Paying a Return Consumer Rate Relief - West Virginia 5.1 2.9 1 year Deferred Wind Power Costs - Virginia 2.1 11.8 1 year Energy Efficiency Rate Adjustment Clause - Virginia 1.5 — 2 years Unrealized Gain on Forward Commitments 1.3 8.4 2 years Other Regulatory Liabilities Approved for Payment — 0.1 various Total Regulatory Liabilities Approved for Payment 627.8 637.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 627.8 $ 637.1
Regulatory Liabilities	a) Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 13.0 $ 7.5 1 year Under-recovered Fuel Costs - does not earn a return 13.1 4.1 1 year Total Current Regulatory Assets $ 26.1 $ 11.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ — $ 11.6 Regulatory Assets Currently Not Earning a Return Cook Uprate Project 36.3 — Cook Plant Turbine 12.8 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 8.1 4.2 Rockport Plant Dry Sorbent Injection System - Indiana 6.6 2.8 Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana — 27.1 Stranded Costs on Abandoned Plants — 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.9 — Total Regulatory Assets Pending Final Regulatory Approval 64.7 59.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 252.8 260.3 28 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.3 6.6 22 years RTO Formation/Integration Costs 1.2 1.5 3 years Other Regulatory Assets Approved for Recovery 1.3 1.0 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (a) 302.6 246.8 32 years Pension and OPEB Funded Status 141.9 126.4 12 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years Postemployment Benefits 11.4 10.7 5 years Unamortized Loss on Reacquired Debt 10.7 12.0 16 years Medicare Subsidy 8.2 9.2 8 years Litigation Settlement - Indiana 7.6 8.6 9 years River Transportation Division Expenses 3.7 — 1 year Peak Demand Reduction/Energy Efficiency 3.6 10.6 2 years Capacity Costs - Indiana 0.4 7.5 1 year Unrealized Loss on Forward Commitments 0.1 3.2 2 years PJM Expense - Indiana — 4.1 Storm Related Costs - Indiana — 1.8 Other Regulatory Assets Approved for Recovery 0.6 1.1 various Total Regulatory Assets Approved for Recovery 851.9 745.0 Total Noncurrent Regulatory Assets $ 916.6 $ 804.3
Indiana Michigan Power Co [Member]
Regulatory Assets	Relieved as removal costs are incurred. I&M December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 13.0 $ 7.5 1 year Under-recovered Fuel Costs - does not earn a return 13.1 4.1 1 year Total Current Regulatory Assets $ 26.1 $ 11.6 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Materials and Supplies $ — $ 11.6 Regulatory Assets Currently Not Earning a Return Cook Uprate Project 36.3 — Cook Plant Turbine 12.8 9.7 Deferred Cook Plant Life Cycle Management Project Costs - Michigan 8.1 4.2 Rockport Plant Dry Sorbent Injection System - Indiana 6.6 2.8 Plant Retirement Costs - Asset Retirement Obligation Costs - Indiana — 27.1 Stranded Costs on Abandoned Plants — 3.9 Other Regulatory Assets Pending Final Regulatory Approval 0.9 — Total Regulatory Assets Pending Final Regulatory Approval 64.7 59.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant 252.8 260.3 28 years Cook Plant, Unit 2 Baffle Bolts - Indiana 6.3 6.6 22 years RTO Formation/Integration Costs 1.2 1.5 3 years Other Regulatory Assets Approved for Recovery 1.3 1.0 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net (a) 302.6 246.8 32 years Pension and OPEB Funded Status 141.9 126.4 12 years Cook Plant Nuclear Refueling Outage Levelization 75.2 26.8 3 years Off-system Sales Margin Sharing - Indiana 24.3 6.8 2 years Postemployment Benefits 11.4 10.7 5 years Unamortized Loss on Reacquired Debt 10.7 12.0 16 years Medicare Subsidy 8.2 9.2 8 years Litigation Settlement - Indiana 7.6 8.6 9 years River Transportation Division Expenses 3.7 — 1 year Peak Demand Reduction/Energy Efficiency 3.6 10.6 2 years Capacity Costs - Indiana 0.4 7.5 1 year Unrealized Loss on Forward Commitments 0.1 3.2 2 years PJM Expense - Indiana — 4.1 Storm Related Costs - Indiana — 1.8 Other Regulatory Assets Approved for Recovery 0.6 1.1 various Total Regulatory Assets Approved for Recovery 851.9 745.0 Total Noncurrent Regulatory Assets $ 916.6 $ 804.3 (a) Includes $74 million and $69 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rate s. I&M December 31, Remaining Refund Period Regulatory Liabilities: 2016 2015 (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 0.3 Total Current Regulatory Liabilities $ — $ 0.3 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs (a) $ 236.5 $ 350.6 (b) Regulatory Liabilities Currently Not Paying a Return Excess Nuclear Decommissioning Funding 731.2 636.5 (c) Spent Nuclear Fuel 44.2 43.4 (c) Deferred Investment Tax Credits 38.8 35.0 20 years Deferred Cook Plant Life Cycle Management Project Costs - Indiana 4.6 — 3 years PJM Expense - Indiana 4.2 — 2 years Unrealized Gain on Forward Commitments 2.4 7.1 2 years Rockport Plant Dry Sorbent Injection 1.7 0.4 2 years Storm Related Costs - Indiana 1.2 — 1 year River Transportation Division Expenses — 1.9 Other Regulatory Liabilities Approved for Payment 0.7 1.3 various Total Regulatory Liabilities Approved for Payment 1,065.5 1,076.2 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 1,065.5 $ 1,076.2
Regulatory Liabilities	a) As of December 31, 2016, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases. (b) Relieved as removal costs are incurred. (c) Relieved when plant is decommissioned. OPCo December 31, Remaining Recovery Period Regulatory Assets: 2016 2015 (in millions) Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Capacity Deferral $ 96.7 $ — Regulatory Assets Currently Not Earning a Return gridSMART ® Costs 4.1 1.3 Total Regulatory Assets Pending Final Regulatory Approval 100.8 1.3 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Phase-In Recovery Rider 218.9 304.5 2 years Capacity Deferral 201.9 358.7 2 years Distribution Decoupling 41.8 37.5 2 years Basic Transmission Cost Rider 19.9 — 2 years RTO Formation/Integration Costs 2.5 3.1 3 years Economic Development Rider 1.7 — 2 years Transmission Cost Recovery Rider — 12.3 Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 225.2 219.4 12 years Income Taxes, Net (a) 126.4 129.0 28 years Unrealized Loss on Forward Commitments 118.6 — 16 years OVEC Purchased Power 22.1 — 2 years Unamortized Loss on Reacquired Debt 9.1 10.4 22 years Medicare Subsidy 8.3 9.3 8 years Postemployment Benefits 6.8 7.3 5 years Distribution Investment Rider 2.0 12.3 2 years Partnership with Ohio Contribution 1.4 2.4 2 years gridSMART ® Costs — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.0 various Total Regulatory Assets Approved for Recovery 1,006.7 1,111.7 Total Noncurrent Regulatory Assets $ 1,107.5 $ 1,113.0
Ohio Power Co [Member]
Regulatory Assets	a) Includes $76 million and $82 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates. OPCo December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - does not pay a return $ 4.2 $ 27.6 1 year Total Current Regulatory Liabilities $ 4.2 $ 27.6 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities pending final regulatory determination: Regulatory Liabilities Currently Not Paying a Return Provision for Regulatory Loss $ — $ 40.6 Other Regulatory Liabilities Pending Final Regulatory Determination 0.2 0.2 Total Regulatory Liabilities Pending Final Regulatory Determination 0.2 40.8 Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs 432.4 422.3 (a) Basic Transmission Cost Rider 0.3 4.9 2 years Economic Development Rider — 5.0 Regulatory Liabilities Currently Not Paying a Return Peak Demand Reduction/Energy Efficiency 29.0 1.5 2 years Enhanced Service Reliability Plan 21.7 8.0 2 years gridSMART ® Costs 11.9 — 2 years Storm Related Costs 5.3 1.3 2 years Deferred Asset Phase-In Rider 4.5 5.1 4 years Unrealized Gain on Forward Commitments — 15.3 Regulatory Settlement — 9.0 Other Regulatory Liabilities Approved for Payment 0.9 1.0 various Total Regulatory Liabilities Approved for Payment 506.0 473.4 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 506.2 $ 514.2
Regulatory Liabilities	a) Relieved as removal costs are incurred. PSO December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 33.8 $ — 1 year Total Current Regulatory Assets $ 33.8 $ — Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 84.5 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.5 — Regulatory Assets Currently Not Earning a Return Storm Related Costs 20.0 12.3 Environmental Control Projects 13.1 — Other Regulatory Assets Pending Final Regulatory Approval — 1.1 Total Regulatory Assets Pending Final Regulatory Approval 118.1 13.4 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Meter Replacement Costs 50.1 35.8 8 years Storm Related Costs 10.8 — 3 years Red Rock Generating Facility 9.1 9.3 40 years Regulatory Assets Currently Not Earning a Return Pension and OPEB Funded Status 98.1 95.1 12 years Deferred System Reliability Rider Expenses 12.5 9.9 1 year Storm Related Costs — 15.4 SPP Base Plan Fees 10.7 — 2 years Peak Demand Reduction/Energy Efficiency 10.3 11.8 2 years Income Taxes, Net 9.3 6.1 33 years Unamortized Loss on Reacquired Debt 5.8 6.8 16 years Medicare Subsidy 3.9 4.4 8 years Rate Case Expenses 1.4 1.2 1 year Vegetation Management — 4.5 Other Regulatory Assets Approved for Recovery 0.1 1.1 various Total Regulatory Assets Approved for Recovery 222.1 201.4 Total Noncurrent Regulatory Assets $ 340.2 $ 214.8 PSO December 31, Remaining Refund Period 2016 2015 Regulatory Liabilities: (in millions) Current Regulatory Liabilities Over-recovered Fuel Costs - pays a return $ — $ 76.1 Total Current Regulatory Liabilities $ — $ 76.1 Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits Regulatory liabilities approved for payment: Regulatory Liabilities Currently Paying a Return Asset Removal Costs $ 279.3 $ 275.5 (a) Regulatory Liabilities Currently Not Paying a Return Deferred Investment Tax Credits 48.0 46.3 38 years Advanced Metering Costs 11.5 11.4 1 year Base Plan Funding Costs — 1.3 Other Regulatory Liabilities Approved for Payment 0.9 0.6 various Total Regulatory Liabilities Approved for Payment 339.7 335.1 Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits $ 339.7 $ 335.1
Public Service Co Of Oklahoma [Member]
Regulatory Assets
Regulatory Liabilities	a) Relieved as removal costs are incurred. SWEPCo December 31, Remaining Recovery Period 2016 2015 Regulatory Assets: (in millions) Current Regulatory Assets Under-recovered Fuel Costs - earns a return $ 8.4 $ 4.1 1 year Total Current Regulatory Assets $ 8.4 $ 4.1 Noncurrent Regulatory Assets Regulatory assets pending final regulatory approval: Regulatory Assets Currently Earning a Return Plant Retirement Costs - Unrecovered Plant $ 75.4 $ — Other Regulatory Assets Pending Final Regulatory Approval 0.8 — Regulatory Assets Currently Not Earning a Return Environmental Controls Projects 11.0 — Shipe Road Transmission Project - FERC 3.1 3.1 Asset Retirement Obligation - Arkansas, Louisiana 2.7 1.7 Rate Case Expense - Texas 1.0 0.3 Other Regulatory Assets Pending Final Regulatory Approval 1.9 0.8 Total Regulatory Assets Pending Final Regulatory Approval 95.9 5.9 Regulatory assets approved for recovery: Regulatory Assets Currently Earning a Return Other Regulatory Assets Approved for Recovery 1.3 0.2 various Regulatory Assets Currently Not Earning a Return Income Taxes, Net 314.2 271.9 34 years Pension and OPEB Funded Status 119.8 108.9 12 years Unamortized Loss on Reacquired Debt 5.4 6.0 27 years Medicare Subsidy 4.3 4.8 8 years Rate Case Expense - Texas 4.2 6.8 2 years Peak Demand Reduction/Energy Efficiency 3.0 1.0 2 years Deferred Restructuring Costs - Louisiana 1.9 3.5 2 years Unrealized Loss on Forward Commitments 0.3 5.5 1 year Other Regulatory Assets Approved for Recovery 0.9 1.3 various Total Regulatory Assets Approved for Recovery 455.3 409.9 Total Noncurrent Regulatory Assets $ 551.2 $ 415.8
Southwestern Electric Power Co [Member]
Regulatory Assets
Regulatory Liabilities	a) Relieved as removal costs are incurred.

Commitments, Guarantees and C42

Commitments, Guarantees and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2016
Contractual Commitments	Contractual Commitments - AEP Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) (b) $ 1,407.8 $ 1,441.6 $ 985.5 $ 371.8 $ 4,206.7 Energy and Capacity Purchase Contracts 215.5 437.1 439.1 1,740.2 2,831.9 Total $ 1,623.3 $ 1,878.7 $ 1,424.6 $ 2,112.0 $ 7,038.6 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 .
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 149.7 January 2017 to February 2018 OPCo 0.6 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
Appalachian Power Co [Member]
Contractual Commitments	(a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . Contractual Commitments - APCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 491.5 $ 433.8 $ 415.0 $ 1.2 $ 1,341.5 Energy and Capacity Purchase Contracts 33.4 68.9 72.4 430.7 605.4 Total $ 524.9 $ 502.7 $ 487.4 $ 431.9 $ 1,946.9
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
Indiana Michigan Power Co [Member]
Contractual Commitments	(a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . Contractual Commitments - I&M Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 292.7 $ 277.8 $ 221.9 $ 266.1 $ 1,058.5 Energy and Capacity Purchase Contracts 118.5 247.7 249.5 497.5 1,113.2 Total $ 411.2 $ 525.5 $ 471.4 $ 763.6 $ 2,171.7
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
Ohio Power Co [Member]
Contractual Commitments	(a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 . Contractual Commitments - OPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Energy and Capacity Purchase Contracts $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2 Total $ 27.1 $ 55.9 $ 58.6 $ 442.6 $ 584.2
Maximum Future Payments for Letters of Credit Uncommitted Facilities	Company Amount Maturity (in millions) AEP $ 149.7 January 2017 to February 2018 OPCo 0.6 September 2017
Public Service Co Of Oklahoma [Member]
Contractual Commitments	Contractual Commitments - PSO Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 63.9 $ 55.5 $ 29.8 $ 14.9 $ 164.1 Energy and Capacity Purchase Contracts 90.6 181.7 179.9 282.3 734.5 Total $ 154.5 $ 237.2 $ 209.7 $ 297.2 $ 898.6 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 .
Southwestern Electric Power Co [Member]
Contractual Commitments	Contractual Commitments - SWEPCo Less Than 1 Year 2-3 Years 4-5 Years After 5 Years Total (in millions) Fuel Purchase Contracts (a) $ 98.4 $ 139.7 $ 69.7 $ 22.6 $ 330.4 Energy and Capacity Purchase Contracts 32.6 66.6 62.5 175.9 337.6 Total $ 131.0 $ 206.3 $ 132.2 $ 198.5 $ 668.0 (a) Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel. (b) Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7 .

Dispositions, Assets and Liab43

Dispositions, Assets and Liabilities Held for Sale and Impairments (Tables)	12 Months Ended
	Dec. 31, 2016
Impaired Assets	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.
Corporate and Other [Member]
Assets and Liabilities Held for Sale and Results of Discontinued Operations	Years Ended December 31, 2015 2014 (in millions) Other Revenues $ 447.1 $ 641.6 Other Operation Expense 321.3 459.5 Maintenance Expense 21.5 32.6 Depreciation and Amortization Expense 26.9 31.5 Taxes Other Than Income Taxes 10.6 14.2 Total Expenses 380.3 537.8 Other Income (Expense) (16.9 ) (17.1 ) Pretax Income of Discontinued Operations 49.9 86.7 Income Tax Expense 19.4 39.0 Equity Earnings of Unconsolidated Subsidiaries (0.1 ) (0.2 ) Income from Discontinued Operations of AEPRO 30.4 47.5 Gain on Sale of Discontinued Operations 240.1 — Income Tax Expense (Benefit) (13.2 ) — Gain on Sale of Discontinued Operations, Net of Tax 253.3 — Total Income on Discontinued Operations as Presented on the Statements of Income $ 283.7 $ 47.5
Generation and Marketing [Member]
Assets and Liabilities Held for Sale and Results of Discontinued Operations	December 31, 2016 Assets: (in millions) Fuel $ 145.5 Materials and Supplies 49.4 Property, Plant and Equipment - Net 1,756.2 Other Class of Assets That Are Not Major 0.1 Total Assets Classified as Held for Sale on the Balance Sheets $ 1,951.2 Liabilities: Long-term Debt $ 134.8 Waterford Plant Upgrade Liability 52.2 Asset Retirement Obligations 36.7 Other Classes of Liabilities That Are Not Major 12.2 Total Liabilities Classified as Held for Sale on the Balance Sheets $ 235.9

Benefit Plans (Tables)

Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2016
Health Care Trend Rates	January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 4,992.9 $ 5,224.9 $ 1,450.6 $ 1,439.0 Service Cost 85.8 93.5 10.2 12.2 Interest Cost 211.6 205.3 60.9 56.8 Actuarial (Gain) Loss 142.7 (200.6 ) 17.3 37.2 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Participant Contributions — — 37.8 33.3 Medicare Subsidy — — 0.8 0.8 Benefit Obligation as of December 31, $ 5,085.8 $ 4,992.9 $ 1,447.4 $ 1,450.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 4,767.6 $ 4,967.5 $ 1,577.4 $ 1,693.9 Actual Gain (Loss) on Plan Assets 315.5 32.4 56.0 (34.0 ) Company Contributions 91.4 97.9 4.9 12.9 Participant Contributions — — 37.8 33.3 Benefit Payments (347.2 ) (330.2 ) (130.2 ) (128.7 ) Fair Value of Plan Assets as of December 31, $ 4,827.3 $ 4,767.6 $ 1,545.9 $ 1,577.4 Funded (Underfunded) Status as of December 31, $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, AEP 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 154.5 $ 185.8 Other Current Liabilities – Accrued Short-term Benefit Liability (5.9 ) (6.3 ) (3.0 ) (3.3 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (252.6 ) (219.0 ) (53.0 ) (55.7 ) Funded (Underfunded) Status $ (258.5 ) $ (225.3 ) $ 98.5 $ 126.8
Amounts Included in AOCI and Regulatory Assets	AEP Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 1,569.8 $ 1,546.1 $ 614.4 $ 577.4 Prior Service Cost (Credit) 1.0 3.3 (485.4 ) (554.4 ) Recorded as Regulatory Assets $ 1,415.6 $ 1,385.2 $ 90.4 $ 15.1 Deferred Income Taxes 54.4 57.5 13.5 2.8 Net of Tax AOCI 100.8 106.7 25.1 5.1
Components of Change in Amounts Included in AOCI and Regulatory Assets	AEP Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 107.5 $ 41.8 $ 68.4 $ 176.3 Amortization of Actuarial Loss (83.8 ) (107.1 ) (31.4 ) (18.8 ) Amortization of Prior Service Credit (Cost) (2.3 ) (2.2 ) 69.0 69.1 Change for the Year Ended December 31, $ 21.4 $ (67.5 ) $ 106.0 $ 226.6
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — —
Components of Net Periodic Benefit Cost	AEP Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 85.8 $ 93.5 $ 71.9 $ 10.2 $ 12.2 $ 14.2 Interest Cost 211.6 205.3 221.0 60.9 56.8 67.2 Expected Return on Plan Assets (280.3 ) (274.8 ) (261.6 ) (107.0 ) (111.0 ) (111.3 ) Amortization of Prior Service Cost (Credit) 2.3 2.2 2.5 (69.0 ) (69.1 ) (69.0 ) Amortization of Net Actuarial Loss 83.8 107.1 124.0 31.4 18.8 22.1 Net Periodic Benefit Cost (Credit) 103.2 133.3 157.8 (73.5 ) (92.3 ) (76.8 ) Capitalized Portion (37.8 ) (48.4 ) (52.2 ) 26.9 33.5 25.3 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 65.4 $ 84.9 $ 105.6 $ (46.6 ) $ (58.8 ) $ (51.5 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 84.2 $ 10.7 $ 10.0 $ 8.1 $ 4.4 $ 4.9 Prior Service Cost 1.0 0.2 0.2 0.1 — — Total Estimated 2017 Amortization $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 Pension Plans – Expected to be Recorded as Regulatory Asset $ 74.1 $ 10.9 $ 9.6 $ 8.2 $ 4.4 $ 4.9 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.2 — 0.4 — — — Total $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 34.4 $ 5.8 $ 4.1 $ 4.0 $ 1.9 $ 2.2 Prior Service Credit (69.0 ) (10.0 ) (9.4 ) (6.9 ) (4.3 ) (5.2 ) Total Estimated 2017 Amortization $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (25.1 ) $ (2.2 ) $ (4.8 ) $ (2.9 ) $ (2.4 ) $ (1.9 ) Deferred Income Taxes (3.3 ) (0.7 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (6.2 ) (1.3 ) (0.3 ) — — (0.7 ) Total $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 72.9 $ 73.6 $ 70.5 APCo 7.3 7.2 7.3 I&M 10.9 10.6 10.5 OPCo 5.6 5.4 5.2 PSO 4.3 4.2 4.0 SWEPCo 5.7 5.7 5.3
Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Benefit Costs [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Appalachian Power Co [Member]
Health Care Trend Rates	January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 653.4 $ 702.8 $ 262.2 $ 267.1 Service Cost 8.1 8.7 1.0 1.1 Interest Cost 27.2 26.7 10.8 10.3 Actuarial (Gain) Loss 9.2 (41.4 ) (0.2 ) 2.5 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Participant Contributions — — 6.4 5.7 Medicare Subsidy — — 0.2 0.2 Benefit Obligation as of December 31, $ 654.0 $ 653.4 $ 255.6 $ 262.2 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 603.2 $ 642.3 $ 256.7 $ 280.6 Actual Gain (Loss) on Plan Assets 38.3 (5.7 ) 5.9 (7.7 ) Company Contributions 8.8 10.0 2.7 2.8 Participant Contributions — — 6.4 5.7 Benefit Payments (43.9 ) (43.4 ) (24.8 ) (24.7 ) Fair Value of Plan Assets as of December 31, $ 606.4 $ 603.2 $ 246.9 $ 256.7 Underfunded Status as of December 31, $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 )
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, APCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 25.2 $ 30.8 Other Current Liabilities – Accrued Short-term Benefit Liability — — (2.4 ) (2.6 ) Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (47.6 ) (50.2 ) (31.5 ) (33.7 ) Underfunded Status $ (47.6 ) $ (50.2 ) $ (8.7 ) $ (5.5 )
Amounts Included in AOCI and Regulatory Assets	APCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 216.2 $ 220.8 $ 92.9 $ 86.9 Prior Service Cost (Credit) 0.2 0.3 (70.5 ) (80.6 ) Recorded as Regulatory Assets $ 213.7 $ 218.3 $ 7.7 $ (0.7 ) Deferred Income Taxes 1.0 1.0 5.1 2.4 Net of Tax AOCI 1.7 1.8 9.6 4.6
Components of Change in Amounts Included in AOCI and Regulatory Assets	APCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 6.2 $ (0.3 ) $ 11.4 $ 24.7 Amortization of Actuarial Loss (10.8 ) (13.9 ) (5.4 ) (3.6 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 10.1 10.0 Change for the Year Ended December 31, $ (4.7 ) $ (14.4 ) $ 16.1 $ 31.1
Allocated Assets of Investments	Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — —
Components of Net Periodic Benefit Cost	APCo Pension Plans Other Postretirement Benefit Plans Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 8.1 $ 8.7 $ 7.0 $ 1.0 $ 1.1 $ 1.4 Interest Cost 27.2 26.7 29.6 10.8 10.3 12.8 Expected Return on Plan Assets (35.3 ) (35.0 ) (33.9 ) (17.3 ) (18.1 ) (18.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.2 0.2 (10.1 ) (10.0 ) (10.1 ) Amortization of Net Actuarial Loss 10.8 13.9 16.6 5.4 3.6 4.6 Net Periodic Benefit Cost (Credit) 10.9 14.5 19.5 (10.2 ) (13.1 ) (9.8 ) Capitalized Portion (4.1 ) (5.5 ) (6.8 ) 3.9 5.0 3.4 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 6.8 $ 9.0 $ 12.7 $ (6.3 ) $ (8.1 ) $ (6.4 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 84.2 $ 10.7 $ 10.0 $ 8.1 $ 4.4 $ 4.9 Prior Service Cost 1.0 0.2 0.2 0.1 — — Total Estimated 2017 Amortization $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 Pension Plans – Expected to be Recorded as Regulatory Asset $ 74.1 $ 10.9 $ 9.6 $ 8.2 $ 4.4 $ 4.9 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.2 — 0.4 — — — Total $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 34.4 $ 5.8 $ 4.1 $ 4.0 $ 1.9 $ 2.2 Prior Service Credit (69.0 ) (10.0 ) (9.4 ) (6.9 ) (4.3 ) (5.2 ) Total Estimated 2017 Amortization $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (25.1 ) $ (2.2 ) $ (4.8 ) $ (2.9 ) $ (2.4 ) $ (1.9 ) Deferred Income Taxes (3.3 ) (0.7 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (6.2 ) (1.3 ) (0.3 ) — — (0.7 ) Total $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 72.9 $ 73.6 $ 70.5 APCo 7.3 7.2 7.3 I&M 10.9 10.6 10.5 OPCo 5.6 5.4 5.2 PSO 4.3 4.2 4.0 SWEPCo 5.7 5.7 5.3
Appalachian Power Co [Member] | Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Appalachian Power Co [Member] | Benefit Costs [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Indiana Michigan Power Co [Member]
Health Care Trend Rates	January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 591.5 $ 617.9 $ 166.3 $ 161.7 Service Cost 12.2 12.9 1.5 1.6 Interest Cost 25.3 24.5 7.0 6.4 Actuarial (Gain) Loss 20.1 (28.4 ) 3.8 7.7 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Participant Contributions — — 4.6 4.0 Medicare Subsidy — — 0.1 0.1 Benefit Obligation as of December 31, $ 611.6 $ 591.5 $ 167.6 $ 166.3 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 570.0 $ 591.7 $ 189.0 $ 202.4 Actual Gain (Loss) on Plan Assets 40.6 (0.9 ) 8.7 (2.3 ) Company Contributions 13.0 14.6 — 0.1 Participant Contributions — — 4.6 4.0 Benefit Payments (37.5 ) (35.4 ) (15.7 ) (15.2 ) Fair Value of Plan Assets as of December 31, $ 586.1 $ 570.0 $ 186.6 $ 189.0 Funded (Underfunded) Status as of December 31, $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, I&M 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 19.0 $ 22.7 Deferred Credits and Other Noncurrent Liabilities – Accrued Long-term Benefit Liability (25.5 ) (21.5 ) — — Funded (Underfunded) Status $ (25.5 ) $ (21.5 ) $ 19.0 $ 22.7
Amounts Included in AOCI and Regulatory Assets	I&M Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 133.2 $ 130.0 $ 81.3 $ 77.1 Prior Service Cost (Credit) 0.2 0.3 (66.3 ) (75.7 ) Recorded as Regulatory Assets $ 128.2 $ 125.3 $ 13.7 $ 1.1 Deferred Income Taxes 1.8 1.8 0.5 0.1 Net of Tax AOCI 3.4 3.2 0.8 0.2
Components of Change in Amounts Included in AOCI and Regulatory Assets	I&M Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 13.2 $ 4.7 $ 7.9 $ 24.7 Amortization of Actuarial Loss (10.0 ) (12.6 ) (3.7 ) (2.0 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 9.4 9.4 Change for the Year Ended December 31, $ 3.1 $ (8.1 ) $ 13.6 $ 32.1
Allocated Assets of Investments	Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — —
Components of Net Periodic Benefit Cost	I&M Pension Plans Other Postretirement Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 12.2 $ 12.9 $ 10.0 $ 1.5 $ 1.6 $ 1.9 Interest Cost 25.3 24.5 26.3 7.0 6.4 7.6 Expected Return on Plan Assets (33.6 ) (32.6 ) (31.0 ) (12.9 ) (13.2 ) (13.4 ) Amortization of Prior Service Cost (Credit) 0.1 0.2 0.2 (9.4 ) (9.4 ) (9.4 ) Amortization of Net Actuarial Loss 10.0 12.6 14.6 3.7 2.0 2.4 Net Periodic Benefit Cost (Credit) 14.0 17.6 20.1 (10.1 ) (12.6 ) (10.9 ) Capitalized Portion (3.3 ) (4.0 ) (4.6 ) 2.4 2.9 2.5 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 10.7 $ 13.6 $ 15.5 $ (7.7 ) $ (9.7 ) $ (8.4 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 84.2 $ 10.7 $ 10.0 $ 8.1 $ 4.4 $ 4.9 Prior Service Cost 1.0 0.2 0.2 0.1 — — Total Estimated 2017 Amortization $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 Pension Plans – Expected to be Recorded as Regulatory Asset $ 74.1 $ 10.9 $ 9.6 $ 8.2 $ 4.4 $ 4.9 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.2 — 0.4 — — — Total $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 34.4 $ 5.8 $ 4.1 $ 4.0 $ 1.9 $ 2.2 Prior Service Credit (69.0 ) (10.0 ) (9.4 ) (6.9 ) (4.3 ) (5.2 ) Total Estimated 2017 Amortization $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (25.1 ) $ (2.2 ) $ (4.8 ) $ (2.9 ) $ (2.4 ) $ (1.9 ) Deferred Income Taxes (3.3 ) (0.7 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (6.2 ) (1.3 ) (0.3 ) — — (0.7 ) Total $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 72.9 $ 73.6 $ 70.5 APCo 7.3 7.2 7.3 I&M 10.9 10.6 10.5 OPCo 5.6 5.4 5.2 PSO 4.3 4.2 4.0 SWEPCo 5.7 5.7 5.3
Indiana Michigan Power Co [Member] | Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Indiana Michigan Power Co [Member] | Benefit Costs [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Ohio Power Co [Member]
Health Care Trend Rates	January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 497.5 $ 526.3 $ 168.6 $ 164.7 Service Cost 6.5 6.7 0.8 0.9 Interest Cost 20.6 20.3 7.0 6.4 Actuarial (Gain) Loss 4.7 (19.5 ) (1.0 ) 8.7 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Participant Contributions — — 4.7 4.3 Medicare Subsidy — — 0.1 (0.1 ) Benefit Obligation as of December 31, $ 492.9 $ 497.5 $ 164.0 $ 168.6 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 472.1 $ 498.5 $ 191.6 $ 206.2 Actual Gain (Loss) on Plan Assets 30.9 2.2 2.5 (2.6 ) Company Contributions 7.2 7.7 — — Participant Contributions — — 4.7 4.3 Benefit Payments (36.4 ) (36.3 ) (16.2 ) (16.3 ) Fair Value of Plan Assets as of December 31, $ 473.8 $ 472.1 $ 182.6 $ 191.6 Funded (Underfunded) Status as of December 31, $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, OPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 18.6 $ 23.0 Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (19.1 ) (25.4 ) — — Funded (Underfunded) Status $ (19.1 ) $ (25.4 ) $ 18.6 $ 23.0
Amounts Included in AOCI and Regulatory Assets	OPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 215.4 $ 222.0 $ 58.2 $ 52.6 Prior Service Cost (Credit) 0.1 0.2 (48.5 ) (55.4 ) Recorded as Regulatory Assets $ 215.5 $ 222.2 $ 9.7 $ (2.8 )
Components of Change in Amounts Included in AOCI and Regulatory Assets	OPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial Loss During the Year $ 1.5 $ 5.8 $ 9.4 $ 24.0 Amortization of Actuarial Loss (8.1 ) (10.5 ) (3.8 ) (2.1 ) Amortization of Prior Service Credit (Cost) (0.1 ) (0.2 ) 6.9 7.0 Change for the Year Ended December 31, $ (6.7 ) $ (4.9 ) $ 12.5 $ 28.9
Allocated Assets of Investments	Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — —
Components of Net Periodic Benefit Cost	OPCo Pension Plans Other Postretirement Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 6.5 $ 6.7 $ 5.2 $ 0.8 $ 0.9 $ 1.0 Interest Cost 20.6 20.3 22.1 7.0 6.4 7.6 Expected Return on Plan Assets (27.6 ) (27.5 ) (26.5 ) (13.0 ) (13.4 ) (13.5 ) Amortization of Prior Service Cost (Credit) 0.1 0.2 0.2 (6.9 ) (7.0 ) (6.9 ) Amortization of Net Actuarial Loss 8.1 10.5 12.4 3.8 2.1 2.4 Net Periodic Benefit Cost (Credit) 7.7 10.2 13.4 (8.3 ) (11.0 ) (9.4 ) Capitalized Portion (3.4 ) (4.8 ) (5.5 ) 3.7 5.2 3.8 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 4.3 $ 5.4 $ 7.9 $ (4.6 ) $ (5.8 ) $ (5.6 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 84.2 $ 10.7 $ 10.0 $ 8.1 $ 4.4 $ 4.9 Prior Service Cost 1.0 0.2 0.2 0.1 — — Total Estimated 2017 Amortization $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 Pension Plans – Expected to be Recorded as Regulatory Asset $ 74.1 $ 10.9 $ 9.6 $ 8.2 $ 4.4 $ 4.9 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.2 — 0.4 — — — Total $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 34.4 $ 5.8 $ 4.1 $ 4.0 $ 1.9 $ 2.2 Prior Service Credit (69.0 ) (10.0 ) (9.4 ) (6.9 ) (4.3 ) (5.2 ) Total Estimated 2017 Amortization $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (25.1 ) $ (2.2 ) $ (4.8 ) $ (2.9 ) $ (2.4 ) $ (1.9 ) Deferred Income Taxes (3.3 ) (0.7 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (6.2 ) (1.3 ) (0.3 ) — — (0.7 ) Total $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 72.9 $ 73.6 $ 70.5 APCo 7.3 7.2 7.3 I&M 10.9 10.6 10.5 OPCo 5.6 5.4 5.2 PSO 4.3 4.2 4.0 SWEPCo 5.7 5.7 5.3
Ohio Power Co [Member] | Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Ohio Power Co [Member] | Benefit Costs [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Public Service Co Of Oklahoma [Member]
Health Care Trend Rates	January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 265.4 $ 285.4 $ 77.7 $ 76.7 Service Cost 6.2 6.4 0.6 0.7 Interest Cost 11.2 10.9 3.3 3.0 Actuarial (Gain) Loss 3.1 (17.9 ) 1.0 2.4 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Participant Contributions — — 2.2 1.9 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 266.7 $ 265.4 $ 77.6 $ 77.7 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 262.1 $ 275.5 $ 88.3 $ 96.0 Actual Gain (Loss) on Plan Assets 17.3 0.1 3.1 (2.5 ) Company Contributions 5.8 5.9 — — Participant Contributions — — 2.2 1.9 Benefit Payments (19.2 ) (19.4 ) (7.2 ) (7.1 ) Fair Value of Plan Assets as of December 31, $ 266.0 $ 262.1 $ 86.4 $ 88.3 Funded (Underfunded) Status as of December 31, $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, PSO 2016 2015 2016 2015 (in millions) Employee Benefits and Pension Assets – Prepaid Benefit Costs $ 1.6 $ — $ 8.8 $ 10.6 Other Current Liabilities – Accrued Short-term Benefit Liability (0.2 ) (0.2 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (2.1 ) (3.1 ) — — Funded (Underfunded) Status $ (0.7 ) $ (3.3 ) $ 8.8 $ 10.6
Amounts Included in AOCI and Regulatory Assets	PSO Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 91.0 $ 94.1 $ 37.3 $ 35.2 Prior Service Cost (Credit) — 0.3 (30.2 ) (34.5 ) Recorded as Regulatory Assets $ 91.0 $ 94.4 $ 7.1 $ 0.7
Components of Change in Amounts Included in AOCI and Regulatory Assets	PSO Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 1.3 $ (2.9 ) $ 3.9 $ 10.9 Amortization of Actuarial Loss (4.4 ) (5.7 ) (1.8 ) (1.0 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.2 ) 4.3 4.3 Change for the Year Ended December 31, $ (3.4 ) $ (8.8 ) $ 6.4 $ 14.2
Allocated Assets of Investments	Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — —
Components of Net Periodic Benefit Cost	PSO Pension Plans Other Postretirement Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 6.2 $ 6.4 $ 5.2 $ 0.6 $ 0.7 $ 0.8 Interest Cost 11.2 10.9 12.1 3.3 3.0 3.6 Expected Return on Plan Assets (15.5 ) (15.1 ) (14.6 ) (6.1 ) (6.3 ) (6.3 ) Amortization of Prior Service Cost (Credit) 0.3 0.2 0.3 (4.3 ) (4.3 ) (4.3 ) Amortization of Net Actuarial Loss 4.4 5.7 6.7 1.8 1.0 1.1 Net Periodic Benefit Cost (Credit) 6.6 8.1 9.7 (4.7 ) (5.9 ) (5.1 ) Capitalized Portion (2.4 ) (2.8 ) (3.3 ) 1.7 2.0 1.7 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 4.2 $ 5.3 $ 6.4 $ (3.0 ) $ (3.9 ) $ (3.4 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 84.2 $ 10.7 $ 10.0 $ 8.1 $ 4.4 $ 4.9 Prior Service Cost 1.0 0.2 0.2 0.1 — — Total Estimated 2017 Amortization $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 Pension Plans – Expected to be Recorded as Regulatory Asset $ 74.1 $ 10.9 $ 9.6 $ 8.2 $ 4.4 $ 4.9 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.2 — 0.4 — — — Total $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 34.4 $ 5.8 $ 4.1 $ 4.0 $ 1.9 $ 2.2 Prior Service Credit (69.0 ) (10.0 ) (9.4 ) (6.9 ) (4.3 ) (5.2 ) Total Estimated 2017 Amortization $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (25.1 ) $ (2.2 ) $ (4.8 ) $ (2.9 ) $ (2.4 ) $ (1.9 ) Deferred Income Taxes (3.3 ) (0.7 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (6.2 ) (1.3 ) (0.3 ) — — (0.7 ) Total $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 72.9 $ 73.6 $ 70.5 APCo 7.3 7.2 7.3 I&M 10.9 10.6 10.5 OPCo 5.6 5.4 5.2 PSO 4.3 4.2 4.0 SWEPCo 5.7 5.7 5.3
Public Service Co Of Oklahoma [Member] | Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Public Service Co Of Oklahoma [Member] | Benefit Costs [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Southwestern Electric Power Co [Member]
Health Care Trend Rates	January 1, Health Care Trend Rates 2016 2015 Initial 7.00 % 6.25 % Ultimate 5.00 % 5.00 % Year Ultimate Reached 2024 2020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans	AEP APCo I&M OPCo PSO SWEPCo (in millions) Effect on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost: 1% Increase $ 3.1 $ 0.6 $ 0.3 $ 0.2 $ 0.1 $ 0.1 1% Decrease (2.3 ) (0.5 ) (0.2 ) (0.2 ) (0.1 ) (0.1 ) Effect on the Health Care Component of the Accumulated Postretirement Benefit Obligation: 1% Increase $ 58.8 $ 12.6 $ 5.6 $ 5.5 $ 2.6 $ 2.9 1% Decrease (50.7 ) (10.6 ) (4.9 ) (4.8 ) (2.3 ) (2.6 )
Reconciliation of Changes in Benefit Obligations and Fair Value of Assets	SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Change in Benefit Obligation (in millions) Benefit Obligation as of January 1, $ 282.8 $ 298.2 $ 86.1 $ 85.0 Service Cost 8.1 8.3 0.8 0.8 Interest Cost 12.4 11.8 3.6 3.4 Actuarial (Gain) Loss 13.8 (16.2 ) 1.5 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Participant Contributions — — 2.4 2.1 Medicare Subsidy — — — 0.1 Benefit Obligation as of December 31, $ 296.6 $ 282.8 $ 86.9 $ 86.1 Change in Fair Value of Plan Assets Fair Value of Plan Assets as of January 1, $ 280.6 $ 290.2 $ 97.8 $ 106.4 Actual Gain (Loss) on Plan Assets 18.8 1.6 4.1 (3.3 ) Company Contributions 8.4 8.1 — — Participant Contributions — — 2.4 2.1 Benefit Payments (20.5 ) (19.3 ) (7.5 ) (7.4 ) Fair Value of Plan Assets as of December 31, $ 287.3 $ 280.6 $ 96.8 $ 97.8 Funded (Underfunded) Status as of December 31, $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7
Benefit Amounts Recognized on the Balance Sheets	Pension Plans Other Postretirement Benefit Plans December 31, SWEPCo 2016 2015 2016 2015 (in millions) Deferred Charges and Other Noncurrent Assets – Prepaid Benefit Costs $ — $ — $ 9.9 $ 11.7 Other Current Liabilities – Accrued Short-term Benefit Liability (0.1 ) (0.1 ) — — Employee Benefits and Pension Obligations – Accrued Long-term Benefit Liability (9.2 ) (2.1 ) — — Funded (Underfunded) Status $ (9.3 ) $ (2.2 ) $ 9.9 $ 11.7
Amounts Included in AOCI and Regulatory Assets	SWEPCo Pension Plans Other Postretirement Benefit Plans December 31, 2016 2015 2016 2015 Components (in millions) Net Actuarial Loss $ 103.8 $ 97.1 $ 45.4 $ 43.3 Prior Service Cost (Credit) 0.1 0.4 (36.6 ) (41.6 ) Recorded as Regulatory Assets $ 103.9 $ 97.5 $ 5.7 $ 1.2 Deferred Income Taxes — — 1.1 0.2 Net of Tax AOCI — — 2.0 0.3
Components of Change in Amounts Included in AOCI and Regulatory Assets	SWEPCo Pension Plans Other Postretirement Benefit Plans 2016 2015 2016 2015 Components (in millions) Actuarial (Gain) Loss During the Year $ 11.5 $ (1.8 ) $ 4.0 $ 12.0 Amortization of Actuarial Loss (4.8 ) (6.0 ) (1.9 ) (1.1 ) Amortization of Prior Service Credit (Cost) (0.3 ) (0.3 ) 5.0 5.2 Change for the Year Ended December 31, $ 6.4 $ (8.1 ) $ 7.1 $ 16.1
Allocated Assets of Investments	Pension Plan Other Postretirement December 31, Company 2016 2015 2016 2015 APCo 12.6 % 12.7 % 16.0 % 16.3 % I&M 12.1 % 12.0 % 12.1 % 12.0 % OPCo 9.8 % 9.9 % 11.8 % 12.1 % PSO 5.5 % 5.5 % 5.6 % 5.6 % SWEPCo 6.0 % 5.9 % 6.3 % 6.2 %
Accumulated Benefit Obligation	Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,846.0 $ 641.0 $ 588.5 $ 478.0 $ 252.0 $ 279.8 Nonqualified Pension Plans 69.8 0.3 0.3 — 2.2 1.7 Total as of December 31, 2016 $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 254.2 $ 281.5 Accumulated Benefit Obligation AEP APCo I&M OPCo PSO SWEPCo (in millions) Qualified Pension Plan $ 4,757.1 $ 641.4 $ 571.3 $ 484.1 $ 252.0 $ 267.7 Nonqualified Pension Plans 75.6 0.5 0.4 0.1 2.4 1.6 Total as of December 31, 2015 $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 254.4 $ 269.3
Underfunded Accumulated Benefit Obligation	AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 5,085.8 $ 654.0 $ 611.6 $ 492.9 $ 2.3 $ 1.7 Accumulated Benefit Obligation $ 4,915.8 $ 641.3 $ 588.8 $ 478.0 $ 2.2 $ 1.7 Fair Value of Plan Assets 4,827.3 606.4 586.1 473.8 — — Underfunded Accumulated Benefit Obligation as of December 31, 2016 $ (88.5 ) $ (34.9 ) $ (2.7 ) $ (4.2 ) $ (2.2 ) $ (1.7 ) AEP APCo I&M OPCo PSO SWEPCo (in millions) Projected Benefit Obligation $ 4,992.9 $ 653.4 $ 591.5 $ 497.5 $ 2.6 $ 1.7 Accumulated Benefit Obligation $ 4,832.7 $ 641.9 $ 571.7 $ 484.2 $ 2.4 $ 1.6 Fair Value of Plan Assets 4,767.6 603.2 570.0 472.1 — — Underfunded Accumulated Benefit Obligation as of December 31, 2015 $ (65.1 ) $ (38.7 ) $ (1.7 ) $ (12.1 ) $ (2.4 ) $ (1.6 )
Estimated Contributions and Payments to the Pension and OPEB Plans	Company Pension Plans Other Postretirement Benefit Plans (in millions) AEP $ 98.2 $ 4.3 APCo 10.2 2.4 I&M 13.6 — OPCo 7.6 — PSO 5.5 — SWEPCo 8.7 —
Estimated Payments Expected to be Made by the Pension and OPEB Plans	Pension Plans AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 332.6 $ 43.2 $ 35.7 $ 35.8 $ 19.6 $ 20.1 2018 335.6 42.9 35.9 35.7 19.3 21.3 2019 344.5 43.8 38.6 35.8 20.3 22.0 2020 351.2 44.5 38.7 36.1 20.4 22.6 2021 364.4 46.0 40.2 35.4 21.9 23.6 Years 2022 to 2026, in Total 1,841.2 231.2 216.5 172.6 106.7 122.2 Other Postretirement Benefit Plans: Benefit Payments AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 137.0 $ 25.4 $ 16.6 $ 17.0 $ 7.6 $ 8.0 2018 138.2 25.6 16.7 17.0 7.6 8.1 2019 138.3 25.2 16.8 17.0 7.7 8.2 2020 139.7 25.2 16.9 16.9 7.9 8.4 2021 141.1 25.1 17.2 16.9 7.9 8.7 Years 2022 to 2026, in Total 718.0 122.7 87.6 83.8 41.1 46.6 Other Postretirement Benefit Plans: AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 0.3 $ 0.2 $ — $ — $ — $ — 2018 0.3 0.2 — — — — 2019 0.3 0.2 — — — — 2020 0.3 0.2 — — — — 2021 0.3 0.2 — — — — Years 2022 to 2026, in Total 1.7 1.0 — — — —
Components of Net Periodic Benefit Cost	SWEPCo Pension Plans Other Postretirement Years Ended December 31, 2016 2015 2014 2016 2015 2014 (in millions) Service Cost $ 8.1 $ 8.3 $ 6.6 $ 0.8 $ 0.8 $ 1.0 Interest Cost 12.4 11.8 12.7 3.6 3.4 4.0 Expected Return on Plan Assets (16.4 ) (16.0 ) (15.4 ) (6.8 ) (6.9 ) (7.0 ) Amortization of Prior Service Cost (Credit) 0.3 0.3 0.3 (5.0 ) (5.2 ) (5.2 ) Amortization of Net Actuarial Loss 4.8 6.0 7.1 1.9 1.1 1.2 Net Periodic Benefit Cost (Credit) 9.2 10.4 11.3 (5.5 ) (6.8 ) (6.0 ) Capitalized Portion (2.7 ) (3.2 ) (3.4 ) 1.6 2.1 1.8 Net Periodic Benefit Cost (Credit) Recognized in Expense $ 6.5 $ 7.2 $ 7.9 $ (3.9 ) $ (4.7 ) $ (4.2 )
Estimated Amounts to be Amortized to Net Periodic Benefit Costs	AEP APCo I&M OPCo PSO SWEPCo Pension Plans – Components (in millions) Net Actuarial Loss $ 84.2 $ 10.7 $ 10.0 $ 8.1 $ 4.4 $ 4.9 Prior Service Cost 1.0 0.2 0.2 0.1 — — Total Estimated 2017 Amortization $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 Pension Plans – Expected to be Recorded as Regulatory Asset $ 74.1 $ 10.9 $ 9.6 $ 8.2 $ 4.4 $ 4.9 Deferred Income Taxes 3.9 — 0.2 — — — Net of Tax AOCI 7.2 — 0.4 — — — Total $ 85.2 $ 10.9 $ 10.2 $ 8.2 $ 4.4 $ 4.9 AEP APCo I&M OPCo PSO SWEPCo Other Postretirement Benefit Plans – Components (in millions) Net Actuarial Loss $ 34.4 $ 5.8 $ 4.1 $ 4.0 $ 1.9 $ 2.2 Prior Service Credit (69.0 ) (10.0 ) (9.4 ) (6.9 ) (4.3 ) (5.2 ) Total Estimated 2017 Amortization $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 ) Other Postretirement Benefit Plans – Expected to be Recorded as Regulatory Asset $ (25.1 ) $ (2.2 ) $ (4.8 ) $ (2.9 ) $ (2.4 ) $ (1.9 ) Deferred Income Taxes (3.3 ) (0.7 ) (0.2 ) — — (0.4 ) Net of Tax AOCI (6.2 ) (1.3 ) (0.3 ) — — (0.7 ) Total $ (34.6 ) $ (4.2 ) $ (5.3 ) $ (2.9 ) $ (2.4 ) $ (3.0 )
Cost for Matching Contributions to the Retirement Savings Plans	Year Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 72.9 $ 73.6 $ 70.5 APCo 7.3 7.2 7.3 I&M 10.9 10.6 10.5 OPCo 5.6 5.4 5.2 PSO 4.3 4.2 4.0 SWEPCo 5.7 5.7 5.3
Southwestern Electric Power Co [Member] | Benefit Obligations [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans December 31, Assumption 2016 2015 2016 2015 Discount Rate 4.05 % 4.30 % 4.10 % 4.30 % Pension Plans December 31, Assumption – Rate of Compensation Increase (a) 2016 2015 AEP 4.75 % 4.80 % APCo 4.55 % 4.45 % I&M 4.80 % 4.75 % OPCo 4.85 % 4.85 % PSO 4.90 % 4.85 % SWEPCo 4.75 % 4.80 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Southwestern Electric Power Co [Member] | Benefit Costs [Member]
Actuarial Assumptions	Pension Plans Other Postretirement Benefit Plans January 1, Assumptions 2016 2015 2014 2016 2015 2014 Discount Rate 4.30 % 4.00 % 4.70 % 4.30 % 4.00 % 4.70 % Expected Return on Plan Assets 6.00 % 6.00 % 6.00 % 7.00 % 6.75 % 6.75 % Pension Plans January 1, Assumption – Rate of Compensation Increase (a) 2016 2015 2014 AEP 4.75 % 4.80 % 4.85 % APCo 4.55 % 4.45 % 4.60 % I&M 4.80 % 4.80 % 4.90 % OPCo 4.85 % 4.80 % 5.00 % PSO 4.90 % 4.80 % 4.90 % SWEPCo 4.75 % 4.80 % 4.85 % (a) Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
Pension Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 354.7 $ — $ — $ — $ 354.7 7.3 % International 439.2 — — — 439.2 9.1 % Options — 20.0 — — 20.0 0.4 % Real Estate Investment Trusts 3.1 — — — 3.1 0.1 % Common Collective Trusts (c) — 14.0 — 400.5 414.5 8.6 % Subtotal – Equities 797.0 34.0 — 400.5 1,231.5 25.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 32.3 32.3 0.7 % United States Government and Agency Securities (c) — 423.3 — 17.7 441.0 9.1 % Corporate Debt (c) — 1,932.2 — 10.0 1,942.2 40.2 % Foreign Debt (c) — 373.7 — 12.1 385.8 8.0 % State and Local Government — 11.5 — — 11.5 0.2 % Other – Asset Backed (c) — 5.4 — 7.4 12.8 0.3 % Subtotal – Fixed Income — 2,746.1 — 79.5 2,825.6 58.5 % Infrastructure — — 57.6 — 57.6 1.2 % Real Estate — — 254.9 — 254.9 5.3 % Alternative Investments — — 411.1 — 411.1 8.5 % Securities Lending — 161.6 — — 161.6 3.4 % Securities Lending Collateral (a) — — — (163.3 ) (163.3 ) (3.4 )% Cash and Cash Equivalents (c) — — — 29.7 29.7 0.6 % Other – Pending Transactions and Accrued Income (b) — — — 18.6 18.6 0.4 % Total $ 797.0 $ 2,941.7 $ 723.6 $ 365.0 $ 4,827.3 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 315.7 $ — $ — $ — $ 315.7 6.6 % International 402.3 — — — 402.3 8.4 % Options — 15.6 — — 15.6 0.3 % Real Estate Investment Trusts 4.0 — — — 4.0 0.1 % Common Collective Trusts (c) — 16.1 — 369.7 385.8 8.1 % Subtotal – Equities 722.0 31.7 — 369.7 1,123.4 23.5 % Fixed Income: Common Collective Trust – Debt (c) — — — 34.2 34.2 0.7 % United States Government and Agency Securities (c) — 397.8 — 24.1 421.9 8.9 % Corporate Debt (c) — 1,964.2 — 19.0 1,983.2 41.6 % Foreign Debt (c) — 405.4 0.1 16.0 421.5 8.8 % State and Local Government — 12.8 — — 12.8 0.3 % Other – Asset Backed (c) — 15.8 — 7.6 23.4 0.5 % Subtotal – Fixed Income — 2,796.0 0.1 100.9 2,897.0 60.8 % Infrastructure — — 42.0 — 42.0 0.9 % Real Estate — — 253.7 — 253.7 5.3 % Alternative Investments — — 378.7 — 378.7 8.0 % Securities Lending — 263.0 — — 263.0 5.5 % Securities Lending Collateral (a) — — — (264.7 ) (264.7 ) (5.5 )% Cash and Cash Equivalents (c) — 1.2 — 47.4 48.6 1.0 % Other – Pending Transactions and Accrued Income (b) — — — 25.9 25.9 0.5 % Total $ 722.0 $ 3,091.9 $ 674.5 $ 279.2 $ 4,767.6 100.0 % (a) Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program. (b) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (c) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods.
Pension Plan Assets Level 3 Reconciliation	Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2015 $ 0.1 $ 12.5 $ 235.8 $ 378.9 $ 627.3 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — (3.6 ) 12.5 (25.9 ) (17.0 ) Relating to Assets Sold During the Period — 0.3 23.8 37.6 61.7 Purchases and Sales — 32.8 (18.4 ) (11.9 ) 2.5 Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2015 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Foreign Debt Infrastructure Real Estate Alternative Investments Total Level 3 (in millions) Balance as of January 1, 2016 $ 0.1 $ 42.0 $ 253.7 $ 378.7 $ 674.5 Actual Return on Plan Assets Relating to Assets Still Held as of the Reporting Date — 5.9 5.3 13.7 24.9 Relating to Assets Sold During the Period — 0.9 23.2 21.1 45.2 Purchases and Sales (0.1 ) 8.8 (27.3 ) (2.4 ) (21.0 ) Transfers into Level 3 — — — — — Transfers out of Level 3 — — — — — Balance as of December 31, 2016 $ — $ 57.6 $ 254.9 $ 411.1 $ 723.6
Other Postretirement Benefit Plans [Member]
Assets within Fair Value Hierarchy	Asset Class Level 1 Level 2 Level 3 Other Total Year End (in millions) Equities: Domestic $ 465.1 $ — $ — $ — $ 465.1 29.5 % International 484.3 — — — 484.3 30.7 % Options — 15.6 — — 15.6 1.0 % Common Collective Trusts (b) — 12.6 — 19.0 31.6 2.0 % Subtotal – Equities 949.4 28.2 — 19.0 996.6 63.2 % Fixed Income: Common Collective Trust – Debt (b) — — — 100.9 100.9 6.4 % United States Government and Agency Securities — 58.4 — — 58.4 3.7 % Corporate Debt — 117.7 — — 117.7 7.4 % Foreign Debt — 20.7 — — 20.7 1.3 % State and Local Government — 4.2 — — 4.2 0.3 % Other – Asset Backed — 8.4 — — 8.4 0.5 % Subtotal – Fixed Income — 209.4 — 100.9 310.3 19.6 % Trust Owned Life Insurance: International Equities (b) — — — 28.3 28.3 1.8 % United States Bonds (b) — — — 184.3 184.3 11.7 % Subtotal – Trust Owned Life Insurance — — — 212.6 212.6 13.5 % Cash and Cash Equivalents 44.9 7.2 — — 52.1 3.3 % Other – Pending Transactions and Accrued Income (a) — — — 5.8 5.8 0.4 % Total $ 994.3 $ 244.8 $ — $ 338.3 $ 1,577.4 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods. Asset Class Level 1 Level 2 Level 3 Other Total Year End Allocation (in millions) Equities: Domestic $ 517.1 $ — $ — $ — $ 517.1 33.5 % International 435.5 — — — 435.5 28.2 % Options — 15.2 — — 15.2 1.0 % Common Collective Trusts (b) — 10.9 — 20.5 31.4 2.0 % Subtotal – Equities 952.6 26.1 — 20.5 999.2 64.7 % Fixed Income: Common Collective Trust – Debt (b) — — — 93.7 93.7 6.0 % United States Government and Agency Securities — 64.7 — — 64.7 4.2 % Corporate Debt — 121.6 — — 121.6 7.9 % Foreign Debt — 18.6 — — 18.6 1.2 % State and Local Government — 3.0 — — 3.0 0.2 % Other – Asset Backed — 5.9 — — 5.9 0.4 % Subtotal – Fixed Income — 213.8 — 93.7 307.5 19.9 % Trust Owned Life Insurance: International Equities (b) — — — 110.1 110.1 7.1 % United States Bonds (b) — — — 97.4 97.4 6.3 % Subtotal – Trust Owned Life Insurance — — — 207.5 207.5 13.4 % Cash and Cash Equivalents 24.0 10.5 — — 34.5 2.2 % Other – Pending Transactions and Accrued Income (a) — — — (2.8 ) (2.8 ) (0.2 )% Total $ 976.6 $ 250.4 $ — $ 318.9 $ 1,545.9 100.0 % (a) Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement. (b) Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods.

Business Segments (Tables)

Business Segments (Tables)	12 Months Ended
	Dec. 31, 2016
Reportable Segment Information	Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2016 Revenues from: External Customers $ 9,012.4 $ 4,328.3 $ 145.9 $ 2,858.7 $ 34.8 $ — $ 16,380.1 Other Operating Segments 79.5 94.1 366.9 127.3 70.3 (738.1 ) — Total Revenues $ 9,091.9 $ 4,422.4 $ 512.8 $ 2,986.0 $ 105.1 $ (738.1 ) $ 16,380.1 Asset Impairments and Other Related Charges $ 10.5 $ — $ — $ 2,257.3 $ — $ — $ 2,267.8 Depreciation and Amortization 1,073.8 649.9 67.1 154.6 0.2 16.7 (d) 1,962.3 Interest and Investment Income 4.8 14.8 0.4 1.4 11.8 (16.9 ) 16.3 Carrying Costs Income 10.5 20.0 (0.3 ) — — (14.0 ) 16.2 Interest Expense 522.1 256.9 50.3 35.8 40.5 (28.4 ) (d) 877.2 Income Tax Expense (Credit) 397.3 205.1 134.1 (666.5 ) (143.7 ) — (73.7 ) Income (Loss) from Continuing Operations $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 83.1 $ — $ 620.5 Income (Loss) from Discontinued Operations, Net of Tax — — — — (2.5 ) — (2.5 ) Net Income (Loss) $ 984.0 $ 482.1 $ 269.3 $ (1,198.0 ) $ 80.6 $ — $ 618.0 Gross Property Additions $ 2,237.0 $ 1,058.3 $ 1,265.8 $ 336.2 $ 9.8 $ (18.1 ) $ 4,889.0 Total Property, Plant and Equipment $ 41,552.6 $ 14,762.2 $ 5,354.0 $ 364.7 $ 356.6 $ (353.5 ) (d) $ 62,036.6 Accumulated Depreciation and Amortization 12,596.7 3,655.0 101.4 42.2 186.0 (184.0 ) (d) 16,397.3 Total Property, Plant and Equipment – Net $ 28,955.9 $ 11,107.2 $ 5,252.6 $ 322.5 $ 170.6 $ (169.5 ) (d) $ 45,639.3 Assets Held for Sale $ — $ — $ — $ 1,951.2 $ — $ — $ 1,951.2 Total Assets $ 37,428.3 $ 14,802.4 $ 6,384.8 $ 3,386.1 $ 20,354.8 $ (18,888.7 ) (d) (e) $ 63,467.7 Investments in Equity Method Investees $ 41.2 $ 1.2 $ 742.0 $ 0.1 $ 24.9 $ — $ 809.4 Long-term Debt Due Within One Year: Non-Affiliated $ 1,519.9 $ 309.4 $ — $ 500.1 $ 548.6 $ — $ 2,878.0 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 10,353.3 4,672.2 2,055.7 — 297.2 — 17,378.4 Total Long-term Debt $ 11,893.2 $ 4,981.6 $ 2,055.7 $ 532.3 $ 845.8 $ (52.2 ) $ 20,256.4 Liabilities Held for Sale $ — $ — $ — $ 235.9 $ — $ — $ 235.9 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2015 Revenues from: External Customers $ 9,069.9 $ 4,392.0 $ 100.6 $ 2,866.7 $ 24.0 $ — $ 16,453.2 Other Operating Segments 102.3 164.6 228.6 546.0 75.0 (1,116.5 ) — Total Revenues $ 9,172.2 $ 4,556.6 $ 329.2 $ 3,412.7 $ 99.0 $ (1,116.5 ) $ 16,453.2 Depreciation and Amortization $ 1,062.6 $ 686.4 $ 43.0 $ 201.4 $ 0.8 $ 15.5 (d) $ 2,009.7 Interest and Investment Income 4.6 6.4 0.2 2.8 9.2 (15.3 ) 7.9 Carrying Costs Income 11.8 11.8 (0.2 ) — — 0.1 23.5 Interest Expense 517.4 276.2 37.2 40.0 30.3 (27.2 ) (d) 873.9 Income Tax Expense (Credit) 449.3 185.5 91.3 194.6 (1.1 ) — 919.6 Income (Loss) from Continuing Operations $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ (42.7 ) $ — $ 1,768.6 Income from Discontinued Operations, Net of Tax — — — — 283.7 — 283.7 Net Income $ 900.2 $ 352.4 $ 192.7 $ 366.0 $ 241.0 $ — $ 2,052.3 Gross Property Additions $ 2,222.3 $ 1,048.4 $ 1,121.3 $ 134.3 $ 4.8 $ (17.8 ) $ 4,513.3 Total Property, Plant and Equipment $ 40,130.3 $ 13,840.5 $ 3,977.6 $ 7,461.3 $ 350.9 $ (279.2 ) (d) $ 65,481.4 Accumulated Depreciation and Amortization 12,335.0 3,529.2 52.3 3,367.0 176.9 (112.2 ) (d) 19,348.2 Total Property, Plant and Equipment – Net $ 27,795.3 $ 10,311.3 $ 3,925.3 $ 4,094.3 $ 174.0 $ (167.0 ) (d) $ 46,133.2 Total Assets $ 35,792.3 $ 14,795.0 $ 5,012.1 $ 5,414.5 $ 20,242.2 $ (19,573.0 ) (d) (e) $ 61,683.1 Investments in Equity Method Investees $ 31.9 $ 0.9 $ 630.8 $ 0.1 $ 56.8 $ — $ 720.5 Long-term Debt Due Within One Year: Non-Affiliated $ 935.4 $ 824.7 $ — $ 71.6 $ 0.1 $ — $ 1,831.8 Long-term Debt: Affiliated 20.0 — — 32.2 — (52.2 ) — Non-Affiliated 9,833.0 4,776.8 1,648.4 639.5 843.2 — 17,740.9 Total Long-term Debt $ 10,788.4 $ 5,601.5 $ 1,648.4 $ 743.3 $ 843.3 $ (52.2 ) $ 19,572.7 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing Corporate and Other(a) Reconciling Adjustments Consolidated (in millions) 2014 Revenues from: External Customers $ 9,396.8 (b) $ 4,552.6 $ 73.9 $ 2,384.3 (b) $ 22.2 $ (51.2 ) (c) $ 16,378.6 Other Operating Segments 87.6 (b) 261.0 118.0 1,465.3 (b) 73.2 (2,005.1 ) — Total Revenues $ 9,484.4 $ 4,813.6 $ 191.9 $ 3,849.6 $ 95.4 $ (2,056.3 ) $ 16,378.6 Depreciation and Amortization $ 1,033.0 $ 657.8 $ 23.7 $ 226.8 $ — $ (43.7 ) (d) $ 1,897.6 Interest and Investment Income 3.4 10.1 — 4.7 8.6 (19.4 ) 7.4 Carrying Costs Income 6.7 26.5 — — — — 33.2 Interest Expense 525.5 280.3 23.5 45.3 25.1 (31.7 ) (d) 868.0 Income Tax Expense 433.5 211.7 62.9 179.3 15.2 — 902.6 Income from Continuing Operations $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 8.3 $ — $ 1,590.5 Income from Discontinued Operations, Net of Tax — — — — 47.5 — 47.5 Net Income $ 711.8 $ 352.2 $ 150.8 $ 367.4 $ 55.8 $ — $ 1,638.0 Gross Property Additions $ 2,054.7 $ 1,037.7 $ 948.3 $ 164.9 $ 17.2 $ (28.0 ) $ 4,194.8 Total Assets $ 33,705.1 $ 14,524.6 $ 3,570.0 $ 6,326.2 $ 20,512.9 $ (19,094.2 ) (d) (e) $ 59,544.6 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs. (b) Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP’s investments in subsidiary companies.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	12 Months Ended
	Dec. 31, 2016
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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	December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3
Fair Value of Derivative Instruments	AEP Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 264.4 $ 13.2 $ — $ 277.6 $ (183.1 ) $ 94.5 Long-term Risk Management Assets 315.0 7.7 — 322.7 (33.6 ) 289.1 Total Assets 579.4 20.9 — 600.3 (216.7 ) 383.6 Current Risk Management Liabilities 227.2 6.3 — 233.5 (180.1 ) 53.4 Long-term Risk Management Liabilities 301.0 50.1 1.4 352.5 (36.3 ) 316.2 Total Liabilities 528.2 56.4 1.4 586.0 (216.4 ) 369.6 Total MTM Derivative Contract Net Assets (Liabilities) $ 51.2 $ (35.5 ) $ (1.4 ) $ 14.3 $ (0.3 ) $ 14.0 AEP Fair Value of Derivative Instruments December 31, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 368.8 $ 8.2 $ 0.1 $ 377.1 $ (242.7 ) $ 134.4 Long-term Risk Management Assets 364.8 11.7 — 376.5 (54.7 ) 321.8 Total Assets 733.6 19.9 0.1 753.6 (297.4 ) 456.2 Current Risk Management Liabilities 347.0 9.1 0.3 356.4 (269.3 ) 87.1 Long-term Risk Management Liabilities 223.3 19.3 3.2 245.8 (66.7 ) 179.1 Total Liabilities 570.3 28.4 3.5 602.2 (336.0 ) 266.2 Total MTM Derivative Contract Net Assets (Liabilities) $ 163.3 $ (8.5 ) $ (3.4 ) $ 151.4 $ 38.6 $ 190.0 (a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Gain (Loss) on Hedging Instruments	Years Ended December 31, 2016 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1.6 $ 3.2 $ 3.8 Loss on Fair Value Portion of Long-term Debt (1.6 ) (3.3 ) (3.9 )
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on AEP’s Balance Sheets December 31, 2016 December 31, 2015 Commodity Interest Rate Commodity Interest Rate (in millions) Hedging Assets (a) $ 11.2 $ — $ 17.6 $ — Hedging Liabilities (a) 46.7 — 26.1 0.4 AOCI Gain (Loss) Net of Tax (23.1 ) (15.7 ) (5.2 ) (17.2 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4.3 (1.0 ) (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	December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts.
Liabilities Subject to Cross Default Provisions	December 31, 2016 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5
Appalachian Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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	December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3
Fair Value of Derivative Instruments	APCo Fair Value of Derivative Instruments December 31, 2016 Risk Management Contracts - Commodity (a) Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 22.7 $ (20.1 ) $ 2.6 Long-term Risk Management Assets - Nonaffiliated 1.9 (1.9 ) — Total Assets 24.6 (22.0 ) 2.6 Current Risk Management Liabilities - Nonaffiliated 20.6 (20.3 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 2.8 (1.9 ) 0.9 Total Liabilities 23.4 (22.2 ) 1.2 Total MTM Derivative Contract Net Assets $ 1.2 $ 0.2 $ 1.4 APCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (9.1 ) (1.7 )
Collateral Required Under Various Triggering Events	December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts.
Liabilities Subject to Cross Default Provisions	December 31, 2016 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5
Indiana Michigan Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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	December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3
Fair Value of Derivative Instruments	I&M Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - Nonaffiliated $ 14.9 $ (11.4 ) $ 3.5 Long-term Risk Management Assets - Nonaffiliated 1.1 (1.1 ) — Total Assets 16.0 (12.5 ) 3.5 Current Risk Management Liabilities - Nonaffiliated 11.8 (11.5 ) 0.3 Long-term Risk Management Liabilities - Nonaffiliated 1.9 (1.1 ) 0.8 Total Liabilities 13.7 (12.6 ) 1.1 Total MTM Derivative Contract Net Assets $ 2.3 $ 0.1 $ 2.4 I&M Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets - 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (9.1 ) (1.7 )
Collateral Required Under Various Triggering Events	December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts.
Liabilities Subject to Cross Default Provisions	December 31, 2016 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 259.6 $ 0.4 $ 235.8 APCo 0.1 — — I&M 0.1 — — December 31, 2015 Company Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements Amount of Cash Collateral Posted Additional Settlement Liability if Cross Default Provision is Triggered (in millions) AEP $ 300.1 $ 0.8 $ 240.6 APCo 3.7 — 3.7 I&M 2.5 — 2.5
Ohio Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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	December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3
Fair Value of Derivative Instruments	OPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.4 $ (0.2 ) $ 0.2 Long-term Risk Management Assets — — — Total Assets 0.4 (0.2 ) 0.2 Current Risk Management Liabilities 5.9 — 5.9 Long-term Risk Management Liabilities 113.1 — 113.1 Total Liabilities 119.0 — 119.0 Total MTM Derivative Contract Net Liabilities $ (118.6 ) $ (0.2 ) $ (118.8 ) OPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ — $ — $ — 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (9.1 ) (1.7 )
Public Service Co Of Oklahoma [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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	December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3
Fair Value of Derivative Instruments	PSO Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.9 $ (0.1 ) $ 0.8 Long-term Risk Management Assets — — — Total Assets 0.9 (0.1 ) 0.8 Current Risk Management Liabilities — — — Long-term Risk Management Liabilities — — — Total Liabilities — — — Total MTM Derivative Contract Net Assets (Liabilities) $ 0.9 $ (0.1 ) $ 0.8 PSO Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.6 $ — $ 0.6 Long-term Risk Management Assets — — — Total Assets 0.6 — 0.6 Current Risk Management Liabilities 0.5 (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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (9.1 ) (1.7 )
Collateral Required Under Various Triggering Events	December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts.
Southwestern Electric Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments December 31, 2016 Primary Risk Exposure Unit of Measure AEP APCo I&M OPCo PSO SWEPCo (in millions) Commodity: Power MWhs 348.0 51.9 19.9 11.2 11.9 14.2 Coal Tons 1.5 — 0.5 — — 1.0 Natural Gas MMBtus 32.8 — — — — — Heating Oil and Gasoline Gallons 7.4 1.4 0.7 1.6 0.8 0.9 Interest Rate USD $ 75.2 $ 0.1 $ 0.1 $ — $ — $ — Interest Rate and Foreign Currency USD $ 500.0 $ — $ — $ — $ — $ — 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	December 31, 2016 2015 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in millions) AEP $ 7.9 $ 7.6 $ 5.8 $ 44.4 APCo 0.5 0.7 — 3.1 I&M 0.3 0.4 — 0.6 OPCo 0.2 — — 0.5 PSO 0.1 — — 0.3 SWEPCo 0.1 — — 0.3
Fair Value of Derivative Instruments	SWEPCo Fair Value of Derivative Instruments December 31, 2016 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 1.1 $ (0.2 ) $ 0.9 Long-term Risk Management Assets — — — Total Assets 1.1 (0.2 ) 0.9 Current Risk Management Liabilities 0.4 (0.1 ) 0.3 Long-term Risk Management Liabilities — — — Total Liabilities 0.4 (0.1 ) 0.3 Total MTM Derivative Contract Net Assets (Liabilities) $ 0.7 $ (0.1 ) $ 0.6 SWEPCo Fair Value of Derivative Instruments December 31, 2015 Risk Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location (in millions) Current Risk Management Assets $ 0.8 $ — $ 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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.” (b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.” (c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain (Loss) Recognized on Risk Management Contracts	Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2016 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 4.0 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues 0.1 — — — — — Generation & Marketing Revenues 59.4 — — — — — Electric Generation, Transmission and Distribution Revenues — (0.6 ) 4.1 0.1 — — Sales to AEP Affiliates — 2.1 5.8 — — — Purchased Electricity for Resale 6.6 3.5 0.3 — — — Other Operation Expense (1.6 ) (0.1 ) (0.1 ) (0.3 ) (0.1 ) (0.3 ) Maintenance Expense (1.8 ) (0.4 ) (0.1 ) (0.4 ) (0.2 ) (0.2 ) Regulatory Assets (a) (117.4 ) 0.6 3.1 (127.7 ) 0.4 5.2 Regulatory Liabilities (a) 79.1 51.4 13.9 (15.2 ) 6.5 15.7 Total Gain (Loss) on Risk Management Contracts $ 28.4 $ 56.5 $ 27.0 $ (143.5 ) $ 6.6 $ 20.4 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2015 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 6.7 $ — $ — $ — $ — $ — Transmission and Distribution Utilities Revenues (4.3 ) — — — — — Generation & Marketing Revenues 54.9 — — — — — Electric Generation, Transmission and Distribution Revenues — 1.1 3.3 (4.3 ) — — Sales to AEP Affiliates — 2.4 8.2 — — — Purchased Electricity for Resale 6.4 2.0 0.4 — — — Other Operation Expense (3.3 ) (0.4 ) (0.4 ) (0.6 ) (0.4 ) (0.5 ) Maintenance Expense (3.3 ) (0.7 ) (0.4 ) (0.5 ) (0.4 ) (0.4 ) Regulatory Assets (a) (0.9 ) 3.4 (2.7 ) — 0.6 (4.3 ) Regulatory Liabilities (a) 30.2 28.7 7.5 (24.7 ) 4.4 15.1 Total Gain (Loss) on Risk Management Contracts $ 86.4 $ 36.5 $ 15.9 $ (30.1 ) $ 4.2 $ 9.9 Amount of Gain (Loss) Recognized on Risk Management Contracts Year Ended December 31, 2014 Location of Gain (Loss) AEP APCo I&M OPCo PSO SWEPCo (in millions) Vertically Integrated Utilities Revenues $ 35.4 $ — $ — $ — $ — $ — Generation & Marketing Revenues 52.5 — — — — — Electric Generation, Transmission and Distribution Revenues — 8.7 13.2 — 0.2 — Sales to AEP Affiliates — — (0.9 ) — 0.9 — Regulatory Assets (a) (11.4 ) (4.1 ) (0.5 ) — (1.0 ) (1.1 ) Regulatory Liabilities (a) 193.2 49.6 37.4 86.0 0.3 16.9 Total Gain on Risk Management Contracts $ 269.7 $ 54.2 $ 49.2 $ 86.0 $ 0.4 $ 15.8 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.
Impact of Cash Flow Hedges on the Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Balance Sheets December 31, 2016 December 31, 2015 Interest Rate and Foreign Currency Company AOCI Gain (Loss) Net of Tax Expected to be Reclassified to Net Income During the Next Twelve Months AOCI Gain (Loss) Expected to be (in millions) APCo $ 2.9 $ 0.7 $ 3.6 $ 0.7 I&M (12.0 ) (1.3 ) (13.3 ) (1.3 ) OPCo 3.0 1.1 4.3 1.2 PSO 3.4 0.8 4.2 0.8 SWEPCo (7.4 ) (1.4 ) (9.1 ) (1.7 )
Collateral Required Under Various Triggering Events	December 31, 2016 December 31, 2015 Company Amount of Collateral Amount of Amount of Collateral Have Been Required to Post Attributable to RTOs and ISOs Amount of Attributable to (in millions) AEP $ 9.3 $ 280.3 (a) $ 17.5 $ 297.8 (a) APCo 1.0 — 4.9 0.1 I&M 0.6 — 3.3 0.1 PSO 2.1 3.2 — 3.2 SWEPCo 2.5 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 contracts.

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Book Values and Fair Values of Long-term Debt	December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
Other Temporary Investments	December 31, 2016 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 211.7 $ — $ — $ 211.7 Fixed Income Securities – Mutual Funds (b) 92.7 — (1.0 ) 91.7 Equity Securities – Mutual Funds 14.4 13.9 — 28.3 Total Other Temporary Investments $ 318.8 $ 13.9 $ (1.0 ) $ 331.7 December 31, 2015 Other Temporary Investments Cost Gross Unrealized Gains Gross Fair Value (in millions) Restricted Cash (a) $ 271.0 $ — $ — $ 271.0 Fixed Income Securities – Mutual Funds (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	Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — Purchases of Investments 2.3 10.7 1.6 Gross Realized Gains on Investment Sales — — — Gross Realized Losses on Investment Sales — — —
Nuclear Trust Fund Investments	December 31, 2016 2015 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 18.7 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 785.4 27.1 (5.5 ) 731.1 35.9 (2.6 ) Corporate Debt 60.9 2.3 (1.4 ) 57.9 3.2 (1.1 ) State and Local Government 121.1 0.4 (0.7 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 967.4 29.8 (7.6 ) 811.2 40.2 (4.0 ) Equity Securities – Domestic 1,270.1 677.9 (79.6 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,256.2 $ 707.7 $ (87.2 ) $ 2,106.4 $ 611.8 $ (83.3 )
Securities Activity Within the Decommissioning and SNF Trusts	Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ 2,957.7 $ 2,218.4 $ 1,031.8 Purchases of Investments 3,000.0 2,272.0 1,086.4 Gross Realized Gains on Investment Sales 46.1 69.1 32.3 Gross Realized Losses on Investment Sales 24.4 53.0 15.4
Investments Classified by Contractual Maturity Date [Table Text Block]	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 229.5 1 year – 5 years 335.3 5 years – 10 years 204.6 After 10 years 198.0 Total $ 967.4
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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 201.8 $ 210.5 Other Temporary Investments Restricted Cash (a) 173.8 5.1 — 32.8 211.7 Fixed Income Securities – Mutual Funds 91.7 — — — 91.7 Equity Securities – Mutual Funds (b) 28.3 — — — 28.3 Total Other Temporary Investments 293.8 5.1 — 32.8 331.7 Risk Management Assets Risk Management Commodity Contracts (c) (d) 6.0 379.9 192.2 (205.7 ) 372.4 Cash Flow Hedges: Commodity Hedges (c) — 16.8 1.7 (7.3 ) 11.2 Total Risk Management Assets 6.0 396.7 193.9 (213.0 ) 383.6 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,585.9 $ 1,369.2 $ 193.9 $ 33.0 $ 3,182.0 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 8.2 $ 352.0 $ 166.7 $ (205.4 ) $ 321.5 Cash Flow Hedges: Commodity Hedges (c) — 29.3 24.7 (7.3 ) 46.7 Fair Value Hedges — 1.4 — — 1.4 Total Risk Management Liabilities $ 8.2 $ 382.7 $ 191.4 $ (212.7 ) $ 369.6 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 Classified as Level 3	Year Ended December 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2016 AEP Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 183.8 $ 187.1 Discounted Cash Flow Forward Market Price (a) $ 6.51 $ 86.59 $ 39.40 Counterparty Credit Risk (b) 35 824 391 FTRs 10.1 4.3 Discounted Cash Flow Forward Market Price (a) (7.99 ) 8.91 0.86 Total $ 193.9 $ 191.4 Significant Unobservable Inputs 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	December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ 15.8 $ — $ — $ 0.1 $ 15.9 Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) — 20.5 3.9 (21.8 ) 2.6 Total Assets $ 15.8 $ 20.5 $ 3.9 $ (21.7 ) $ 18.5 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 20.7 $ 2.5 $ (22.0 ) $ 1.2 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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 Classified as Level 3	Year Ended December 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2016 APCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.4 $ 0.4 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 3.5 2.1 Discounted Cash Flow Forward Market Price (0.23 ) 8.91 2.37 Total $ 3.9 $ 2.5 Significant Unobservable Inputs 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 (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)
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long-term Debt	December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
Nuclear Trust Fund Investments	December 31, 2016 2015 Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments Fair Value Gross Unrealized Gains Other-Than- Temporary Impairments (in millions) Cash and Cash Equivalents $ 18.7 $ — $ — $ 168.3 $ — $ — Fixed Income Securities: United States Government 785.4 27.1 (5.5 ) 731.1 35.9 (2.6 ) Corporate Debt 60.9 2.3 (1.4 ) 57.9 3.2 (1.1 ) State and Local Government 121.1 0.4 (0.7 ) 22.2 1.1 (0.3 ) Subtotal Fixed Income Securities 967.4 29.8 (7.6 ) 811.2 40.2 (4.0 ) Equity Securities – Domestic 1,270.1 677.9 (79.6 ) 1,126.9 571.6 (79.3 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,256.2 $ 707.7 $ (87.2 ) $ 2,106.4 $ 611.8 $ (83.3 )
Securities Activity Within the Decommissioning and SNF Trusts	Years Ended December 31, 2016 2015 2014 (in millions) Proceeds from Investment Sales $ 2,957.7 $ 2,218.4 $ 1,031.8 Purchases of Investments 3,000.0 2,272.0 1,086.4 Gross Realized Gains on Investment Sales 46.1 69.1 32.3 Gross Realized Losses on Investment Sales 24.4 53.0 15.4
Investments Classified by Contractual Maturity Date [Table Text Block]	Fair Value of Fixed Income Securities (in millions) Within 1 year $ 229.5 1 year – 5 years 335.3 5 years – 10 years 204.6 After 10 years 198.0 Total $ 967.4
Fair Value, Assets and Liabilities Measured on Recurring Basis	I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 12.8 $ 3.0 $ (12.3 ) $ 3.5 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 7.3 — — 11.4 18.7 Fixed Income Securities: United States Government — 785.4 — — 785.4 Corporate Debt — 60.9 — — 60.9 State and Local Government — 121.1 — — 121.1 Subtotal Fixed Income Securities — 967.4 — — 967.4 Equity Securities – Domestic (b) 1,270.1 — — — 1,270.1 Total Spent Nuclear Fuel and Decommissioning Trusts 1,277.4 967.4 — 11.4 2,256.2 Total Assets $ 1,277.4 $ 980.2 $ 3.0 $ (0.9 ) $ 2,259.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ — $ 13.3 $ 0.2 $ (12.4 ) $ 1.1 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets – Nonaffiliated and Affiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.0 $ 6.3 $ (11.1 ) $ 12.3 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 160.5 — — 7.8 168.3 Fixed Income Securities: United States Government — 731.1 — — 731.1 Corporate Debt — 57.9 — — 57.9 State and Local Government — 22.2 — — 22.2 Subtotal Fixed Income Securities — 811.2 — — 811.2 Equity Securities – Domestic (b) 1,126.9 — — — 1,126.9 Total Spent Nuclear Fuel and Decommissioning Trusts 1,287.4 811.2 — 7.8 2,106.4 Total Assets $ 1,287.5 $ 828.2 $ 6.3 $ (3.3 ) $ 2,118.7 Liabilities: Risk Management Liabilities – Nonaffiliated Risk Management Commodity Contracts (c) (g) $ 0.1 $ 17.5 $ 2.0 $ (11.7 ) $ 7.9 (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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 Classified as Level 3	Year Ended December 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	(a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs December 31, 2016 I&M Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) Energy Contracts $ 0.3 $ 0.2 Discounted Cash Flow Forward Market Price $ 19.68 $ 48.55 $ 36.34 FTRs 2.7 — Discounted Cash Flow Forward Market Price (7.90 ) 8.91 1.32 Total $ 3.0 $ 0.2 Significant Unobservable Inputs 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	December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Restricted Cash for Securitized Funding (a) $ — $ — $ — $ 27.2 $ 27.2 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.4 — (0.2 ) 0.2 Total Assets $ — $ 0.4 $ — $ 27.0 $ 27.4 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ — $ 119.0 $ — $ 119.0 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 Classified as Level 3	Year Ended December 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	(a) Represents market prices in dollars per MWh. (b) Represents prices of credit default swaps used to calculate counterparty credit risk, reported in basis points. (c) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. Significant Unobservable Inputs December 31, 2016 OPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ — $ 119.0 Discounted Cash Flow Forward Market Price (a) $ 30.14 $ 71.85 $ 47.45 Counterparty Credit Risk (b) 47 340 272 Total $ — $ 119.0 Significant Unobservable Inputs 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	December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds. (b) Amounts represent publicly traded equity securities and equity-based mutual funds. (c) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.” (d) The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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. PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Risk Management Assets Risk Management Commodity Contracts (c) (g) $ — $ 0.2 $ 0.7 $ (0.1 ) $ 0.8 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
Changes in Fair Value of Net Trading Derivatives Classified as Level 3	Year Ended December 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2016 PSO Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.7 $ — Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) Significant Unobservable Inputs 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 (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)
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long-term Debt	December 31, 2016 2015 Company Book Value Fair Value Book Value Fair Value (in millions) AEP $ 20,391.2 (a) $ 22,211.9 (a) $ 19,572.7 $ 21,201.3 APCo 4,033.9 4,613.2 3,930.7 4,416.7 I&M 2,471.4 2,661.6 2,000.0 2,193.6 OPCo 1,763.9 2,092.5 2,157.7 2,472.7 PSO 1,286.0 1,419.0 1,286.1 1,402.9 SWEPCo 2,679.1 2,814.3 2,273.5 2,417.2 (a) Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
Fair Value, Assets and Liabilities Measured on Recurring Basis	SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2016 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 8.7 $ — $ — $ 1.6 $ 10.3 Risk Management Assets Risk Management Commodity Contracts (c) (g) — 0.3 0.8 (0.2 ) 0.9 Total Assets $ 8.7 $ 0.3 $ 0.8 $ 1.4 $ 11.2 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (g) $ — $ 0.3 $ 0.1 $ (0.1 ) $ 0.3 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 December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts. (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 Classified as Level 3	Year Ended December 31, 2016 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 42.8 25.6 7.1 (3.0 ) (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) 26.1 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (23.0 ) — — — — — Settlements (71.4 ) (37.5 ) (11.1 ) 6.2 0.4 (8.4 ) Transfers into Level 3 (d) (e) 13.3 — — — — — Transfers out of Level 3 (e) (2.6 ) 0.1 0.1 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (129.6 ) 1.5 2.4 (138.1 ) 0.7 0.6 Balance as of December 31, 2016 $ 2.5 $ 1.4 $ 2.8 $ (119.0 ) $ 0.7 $ 0.7 Year Ended December 31, 2015 AEP APCo (a) I&M (a) OPCo PSO SWEPCo (in millions) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 13.5 2.1 0.2 0.5 (0.2 ) 9.2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 53.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (4.9 ) — — — — — Settlements (63.0 ) (17.2 ) (14.2 ) (6.7 ) 0.6 (8.7 ) Transfers into Level 3 (d) (e) 28.7 — — — — — Transfers out of Level 3 (e) (18.9 ) 1.2 0.8 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) (13.0 ) 9.8 2.8 (26.3 ) 0.5 0.8 Balance as of December 31, 2015 $ 146.9 $ 11.7 $ 4.3 $ 15.9 $ 0.6 $ 0.8 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of December 31, 2013 $ 117.9 $ 10.6 $ 7.2 $ 2.9 $ — $ — Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (b) (c) 90.0 29.7 18.6 30.8 — — Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (b) 0.7 — — — — — Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 5.7 — — — — — Settlements (108.7 ) (32.6 ) (20.6 ) (33.7 ) — — Transfers into Level 3 (d) (e) (7.6 ) (3.6 ) (2.5 ) — — — Transfers out of Level 3 (e) (21.5 ) — — — — — Changes in Fair Value Allocated to Regulated Jurisdictions (f) 74.3 11.7 12.0 48.4 (0.3 ) (0.5 ) Balance as of December 31, 2014 $ 150.8 $ 15.8 $ 14.7 $ 48.4 $ (0.3 ) $ (0.5 ) (a) Includes both affiliated and nonaffiliated transactions. (b) Included in revenues on the statements of income. (c) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract. (d) Represents existing assets or liabilities that were previously categorized as Level 2. (e) Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred. (f) Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
Significant Unobservable Inputs for Level 3	Significant Unobservable Inputs December 31, 2016 SWEPCo Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in millions) FTRs $ 0.8 $ 0.1 Discounted Cash Flow Forward Market Price $ (7.99 ) $ 1.03 $ (0.36 ) 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)

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Details of Income Taxes as Reported	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 AEP Years Ended December 31, 2015 2014 (in millions) Federal: Current $ 107.3 $ 22.8 Deferred 774.8 800.1 Total Federal 882.1 822.9 State and Local: Current 14.5 22.8 Deferred 23.0 56.9 Total State and Local 37.5 79.7 Income Tax Expense Before Discontinued Operations $ 919.6 $ 902.6
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	AEP Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 618.0 $ 2,052.3 $ 1,638.0 Discontinued Operations (Net of Income Tax of $0, $6.2 and $39 in 2016, 2015 and 2014, Respectively) 2.5 (283.7 ) (47.5 ) Income Tax Expense (Credit) Before Discontinued Operations (73.7 ) 919.6 902.6 Pretax Income $ 546.8 $ 2,688.2 $ 2,493.1 Income Taxes on Pretax Income at Statutory Rate (35%) $ 191.4 $ 940.9 $ 872.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 41.7 53.6 54.0 Investment Tax Credits, Net (12.3 ) (11.6 ) (12.8 ) State and Local Income Taxes, Net (20.7 ) 24.4 54.3 Removal Costs (39.8 ) (28.8 ) (23.9 ) AFUDC (44.8 ) (51.6 ) (41.8 ) Valuation Allowance (128.3 ) 17.2 (2.5 ) U.K. Windfall Tax (12.9 ) — — Tax Adjustments (43.9 ) (20.1 ) (10.1 ) Other (4.1 ) (4.4 ) 12.8 Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 919.6 $ 902.6 Effective Income Tax Rate (13.5 ) % 34.2 % 36.2 %
Reconciliation of Significant Temporary Differences	AEP December 31, 2016 2015 (in millions) Deferred Tax Assets $ 2,753.0 $ 2,503.9 Deferred Tax Liabilities (14,637.4 ) (14,237.1 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 ) Property Related Temporary Differences $ (8,758.1 ) $ (8,533.3 ) Amounts Due from Customers for Future Federal Income Taxes (292.2 ) (263.5 ) Deferred State Income Taxes (976.6 ) (872.0 ) Securitized Assets (535.6 ) (633.2 ) Regulatory Assets (896.9 ) (873.6 ) Deferred Income Taxes on Other Comprehensive Loss 88.7 72.2 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Net Operating Loss Carryforward 101.2 39.6 Tax Credit Carryforward 45.1 85.0 Valuation Allowance (1.8 ) (130.0 ) All Other, Net 8.6 (9.8 ) Net Deferred Tax Liabilities $ (11,884.4 ) $ (11,733.2 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — —
Summary of Interest Income, Expense And Reversal	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2
Amounts Accrued For Interest Related to Uncertain Tax Positions	Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9
Appalachian Power Co [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	APCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 369.1 $ 340.6 $ 215.4 Income Tax Expense 199.1 194.3 154.9 Pretax Income $ 568.2 $ 534.9 $ 370.3 Income Taxes on Pretax Income at Statutory Rate (35%) $ 198.9 $ 187.2 $ 129.6 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 19.3 19.8 23.5 Investment Tax Credits, Net (0.1 ) (0.3 ) (0.6 ) State and Local Income Taxes, Net 6.0 7.2 6.5 Removal Costs (12.0 ) (9.9 ) (6.8 ) AFUDC (6.1 ) (7.0 ) (3.8 ) Valuation Allowance (1.7 ) 1.7 (2.5 ) Other (5.2 ) (4.4 ) 9.0 Income Tax Expense $ 199.1 $ 194.3 $ 154.9 Effective Income Tax Rate 35.0 % 36.3 % 41.8 %
Reconciliation of Significant Temporary Differences	APCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 413.5 $ 412.9 Deferred Tax Liabilities (3,085.8 ) (2,939.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 ) Property Related Temporary Differences $ (2,031.9 ) $ (1,866.0 ) Amounts Due from Customers for Future Federal Income Taxes (73.1 ) (68.2 ) Deferred State Income Taxes (319.3 ) (308.7 ) Regulatory Assets (159.9 ) (169.1 ) Securitized Assets (106.9 ) (114.8 ) Deferred Income Taxes on Other Comprehensive Loss 4.5 1.5 Tax Credit Carryforward 11.7 19.2 All Other, Net 2.6 (20.9 ) Net Deferred Tax Liabilities $ (2,672.3 ) $ (2,527.0 )
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — —
Summary of Interest Income, Expense And Reversal	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2
Amounts Accrued For Interest Related to Uncertain Tax Positions	Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9
Indiana Michigan Power Co [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	I&M Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 239.9 $ 204.8 $ 155.6 Income Tax Expense 67.5 96.1 79.6 Pretax Income $ 307.4 $ 300.9 $ 235.2 Income Taxes on Pretax Income at Statutory Rate (35%) $ 107.6 $ 105.3 $ 82.3 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 6.7 9.5 12.9 Investment Tax Credits, Net (4.7 ) (3.3 ) (4.9 ) State and Local Income Taxes, Net 2.4 5.8 7.7 Removal Costs (21.3 ) (12.6 ) (11.3 ) AFUDC (7.3 ) (6.2 ) (10.0 ) Tax Adjustments (14.2 ) (4.2 ) 1.2 Other (1.7 ) 1.8 1.7 Income Tax Expense $ 67.5 $ 96.1 $ 79.6 Effective Income Tax Rate 22.0 % 31.9 % 33.8 %
Reconciliation of Significant Temporary Differences	I&M December 31, 2016 2015 (in millions) Deferred Tax Assets $ 912.9 $ 837.4 Deferred Tax Liabilities (2,440.3 ) (2,198.9 ) Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 ) Property Related Temporary Differences $ (579.4 ) $ (521.6 ) Amounts Due from Customers for Future Federal Income Taxes (50.4 ) (42.7 ) Deferred State Income Taxes (158.7 ) (124.8 ) Deferred Income Taxes on Other Comprehensive Loss 8.8 9.0 Accrued Nuclear Decommissioning (666.8 ) (614.6 ) Regulatory Assets (81.0 ) (70.2 ) Net Operating Loss Carryforward 7.1 — All Other, Net (7.0 ) 3.4 Net Deferred Tax Liabilities $ (1,527.4 ) $ (1,361.5 )
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — —
Summary of Interest Income, Expense And Reversal	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2
Amounts Accrued For Interest Related to Uncertain Tax Positions	Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9
Ohio Power Co [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	OPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 282.2 $ 232.7 $ 216.4 Income Tax Expense 143.8 126.5 132.2 Pretax Income $ 426.0 $ 359.2 $ 348.6 Income Taxes on Pretax Income at Statutory Rate (35%) $ 149.1 $ 125.7 $ 122.0 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 7.1 8.2 6.7 Investment Tax Credits, Net — (0.1 ) (0.2 ) State and Local Income Taxes, Net 3.8 0.7 8.8 Other (16.2 ) (8.0 ) (5.1 ) Income Tax Expense $ 143.8 $ 126.5 $ 132.2 Effective Income Tax Rate 33.8 % 35.2 % 37.9 %
Reconciliation of Significant Temporary Differences	OPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 232.4 $ 162.4 Deferred Tax Liabilities (1,578.5 ) (1,545.6 ) Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 ) Property Related Temporary Differences $ (1,090.8 ) $ (1,022.8 ) Amounts Due from Customers for Future Federal Income Taxes (43.6 ) (44.6 ) Deferred State Income Taxes (34.6 ) (34.4 ) Regulatory Assets (174.1 ) (220.0 ) Deferred Income Taxes on Other Comprehensive Loss (1.6 ) (2.3 ) Deferred Fuel and Purchased Power (117.6 ) (117.4 ) All Other, Net 116.2 58.3 Net Deferred Tax Liabilities $ (1,346.1 ) $ (1,383.2 )
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — —
Summary of Interest Income, Expense And Reversal	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2
Amounts Accrued For Interest Related to Uncertain Tax Positions	Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9
Public Service Co Of Oklahoma [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1 Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	PSO Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 100.0 $ 92.5 $ 86.9 Income Tax Expense 54.4 51.3 50.6 Pretax Income $ 154.4 $ 143.8 $ 137.5 Income Taxes on Pretax Income at Statutory Rate (35%) $ 54.0 $ 50.3 $ 48.1 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 0.8 0.5 0.2 Investment Tax Credits, Net (1.4 ) (1.8 ) (0.8 ) State and Local Income Taxes, Net 4.2 5.1 4.8 AFUDC (2.2 ) (3.1 ) (1.1 ) Other (1.0 ) 0.3 (0.6 ) Income Tax Expense $ 54.4 $ 51.3 $ 50.6 Effective Income Tax Rate 35.2 % 35.7 % 36.8 %
Reconciliation of Significant Temporary Differences	PSO December 31, 2016 2015 (in millions) Deferred Tax Assets $ 153.8 $ 141.2 Deferred Tax Liabilities (1,212.6 ) (1,113.0 ) Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 ) Property Related Temporary Differences $ (927.3 ) $ (861.9 ) Amounts Due from Customers for Future Federal Income Taxes (3.2 ) (2.2 ) Deferred State Income Taxes (128.5 ) (117.0 ) Regulatory Assets (67.6 ) (54.3 ) Deferred Income Taxes on Other Comprehensive Loss (1.8 ) (2.3 ) Deferred Federal Income Taxes on Deferred State Income Taxes 50.6 46.6 Net Operating Loss Carryforward 16.5 7.1 Tax Credit Carryforward — 0.6 All Other, Net 2.5 11.6 Net Deferred Tax Liabilities $ (1,058.8 ) $ (971.8 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — —
Summary of Interest Income, Expense And Reversal	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2
Amounts Accrued For Interest Related to Uncertain Tax Positions	Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9
Southwestern Electric Power Co [Member]
Details of Income Taxes as Reported	Year Ended December 31, 2015 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ (32.9 ) $ 5.2 $ 89.0 $ (6.4 ) $ 44.3 Deferred 227.5 94.2 37.6 58.3 41.9 Deferred Investment Tax Credits (0.3 ) (3.3 ) (0.1 ) (0.6 ) (1.4 ) Income Tax Expense $ 194.3 $ 96.1 $ 126.5 $ 51.3 $ 84.8 Year Ended December 31, 2014 APCo I&M OPCo PSO SWEPCo (in millions) Income Tax Expense (Credit): Current $ 10.9 $ 14.3 $ 58.1 $ (24.2 ) $ (171.6 ) Deferred 144.7 70.2 74.4 74.7 239.4 Deferred Investment Tax Credits (0.7 ) (4.9 ) (0.3 ) 0.1 (1.4 ) Income Tax Expense $ 154.9 $ 79.6 $ 132.2 $ 50.6 $ 66.4 Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Federal: Current $ (30.7 ) $ 64.1 $ (44.8 ) $ 178.8 $ (28.0 ) $ (96.7 ) Deferred (28.8 ) 125.8 104.9 (40.8 ) 77.2 172.6 Deferred Investment Tax Credits 17.6 (0.1 ) 3.8 — (1.4 ) (1.2 ) Total Federal (41.9 ) 189.8 63.9 138.0 47.8 74.7 State and Local: Current (10.5 ) 4.4 3.4 4.2 (1.9 ) (12.6 ) Deferred (21.2 ) 4.9 0.2 1.6 5.3 (10.0 ) Deferred Investment Tax Credits (0.1 ) — — — 3.2 — Total State and Local (31.8 ) 9.3 3.6 5.8 6.6 (22.6 ) Income Tax Expense (Credit) Before Discontinued Operations $ (73.7 ) $ 199.1 $ 67.5 $ 143.8 $ 54.4 $ 52.1
Reconciliation of Federal Statutory Tax Rate to Reported Tax Rate	SWEPCo Years Ended December 31, 2016 2015 2014 (in millions) Net Income $ 169.7 $ 196.0 $ 144.6 Income Tax Expense 52.1 84.8 66.4 Pretax Income $ 221.8 $ 280.8 $ 211.0 Income Taxes on Pretax Income at Statutory Rate (35%) $ 77.6 $ 98.3 $ 73.8 Increase (Decrease) in Income Taxes Resulting from the Following Items: Depreciation 3.2 3.1 2.9 Depletion (5.5 ) (5.5 ) (4.1 ) Investment Tax Credits, Net (1.2 ) (1.4 ) (1.4 ) State and Local Income Taxes, Net (14.7 ) 4.8 3.1 AFUDC (3.9 ) (9.2 ) (4.2 ) Other (3.4 ) (5.3 ) (3.7 ) Income Tax Expense $ 52.1 $ 84.8 $ 66.4 Effective Income Tax Rate 23.5 % 30.2 % 31.5 %
Reconciliation of Significant Temporary Differences	SWEPCo December 31, 2016 2015 (in millions) Deferred Tax Assets $ 230.5 $ 194.7 Deferred Tax Liabilities (1,837.4 ) (1,594.5 ) Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 ) Property Related Temporary Differences $ (1,445.2 ) $ (1,275.1 ) Amounts Due from Customers for Future Federal Income Taxes (48.2 ) (47.8 ) Deferred State Income Taxes (175.1 ) (132.3 ) Regulatory Assets (40.7 ) (26.1 ) Deferred Income Taxes on Other Comprehensive Loss 5.1 5.0 Impairment Loss - Turk Plant 20.3 20.7 Net Operating Loss Carryforward 40.3 19.7 Tax Credit Carryforward 0.1 0.7 All Other, Net 36.5 35.4 Net Deferred Tax Liabilities $ (1,606.9 ) $ (1,399.8 )
State Net Income Tax Operating Loss Carryforwards	Company State State Net Income Tax Operating Loss Carryforward Year of Expiration (in millions) AEP Arkansas $ 16.7 2021 AEP Kentucky 89.7 2036 AEP Louisiana 509.1 2036 AEP Missouri 6.3 2036 AEP Oklahoma 529.9 2036 PSO Oklahoma 273.2 2036 SWEPCo Arkansas 16.2 2021 SWEPCo Louisiana 508.3 2036 SWEPCo Oklahoma 4.2 2036
Summary of Tax Credit Carryforwards	Company Total Federal Tax Credit Carryforward Federal Tax Credit Carryforward Subject to Expiration Total State Tax Credit Carryforward State Tax Credit Carryforward Subject to Expiration (in millions) AEP $ 53.6 $ 34.3 $ 26.6 $ 26.6 APCo 11.7 4.5 — — I&M 9.0 8.5 — — OPCo 8.6 — — — PSO — — 26.6 26.6 SWEPCo 0.1 — — —
Summary of Interest Income, Expense And Reversal	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ — $ 0.2 $ 0.2 $ — $ — Interest Income 9.9 0.1 — — 0.3 — Reversal of Prior Period Interest Expense 3.3 — — — 0.7 1.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.7 $ 0.4 $ 0.2 $ 1.0 $ 0.1 $ 0.4 Interest Income 0.8 — — — — — Reversal of Prior Period Interest Expense — — — — — — Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Interest Expense $ 2.9 $ — $ — $ 0.1 $ 0.1 $ 0.2 Interest Income 1.2 — — — — — Reversal of Prior Period Interest Expense 2.0 0.2 0.3 0.2 0.1 0.2
Amounts Accrued For Interest Related to Uncertain Tax Positions	Years Ended December 31, 2016 2015 Payment of Payment of Receipt of Interest and Receipt of Interest and Company Interest Penalties Interest Penalties (in millions) AEP $ 2.9 $ 5.8 $ 44.7 $ 7.2 APCo — 0.1 — — I&M — 0.9 — 0.6 OPCo — 1.7 — 0.6 PSO 0.6 — — 0.4 SWEPCo 0.1 — — 1.4
Reconciliation of Beginning and Ending Unrecognized Tax Benefits	AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2016 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 Increase – Tax Positions Taken During a Prior Period 86.0 — 1.8 — 0.1 1.3 Decrease – Tax Positions Taken During a Prior Period (161.2 ) (0.3 ) (0.4 ) — (1.3 ) (9.3 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (13.0 ) — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2016 $ 98.8 $ — $ 3.8 $ 6.9 $ 0.1 $ 1.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2015 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5 Increase – Tax Positions Taken During a Prior Period 5.4 0.3 0.1 — — 1.8 Decrease – Tax Positions Taken During a Prior Period (0.4 ) — — — — — Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities — — — — — — Decrease – Lapse of the Applicable Statute of Limitations — — — — — — Balance as of December 31, 2015 $ 187.0 $ 0.3 $ 2.4 $ 6.9 $ 1.3 $ 9.3 AEP APCo I&M OPCo PSO SWEPCo (in millions) Balance as of January 1, 2014 $ 175.2 $ 1.2 $ 3.2 $ 2.1 $ 2.2 $ 7.6 Increase – Tax Positions Taken During a Prior Period 18.2 — 1.4 6.4 — 1.6 Decrease – Tax Positions Taken During a Prior Period (1.5 ) — — — — (0.8 ) Increase – Tax Positions Taken During the Current Year — — — — — — Decrease – Tax Positions Taken During the Current Year — — — — — — Decrease – Settlements with Taxing Authorities (0.6 ) — (0.7 ) — — — Decrease – Lapse of the Applicable Statute of Limitations (9.3 ) (1.2 ) (1.6 ) (1.6 ) (0.9 ) (0.9 ) Balance as of December 31, 2014 $ 182.0 $ — $ 2.3 $ 6.9 $ 1.3 $ 7.5
Unrecognized Tax Benefits Affecting Effective Tax Rate	Company 2016 2015 2014 (in millions) AEP $ 15.8 $ 100.2 $ 97.2 APCo — 0.2 — I&M 2.5 1.6 1.6 OPCo 4.4 4.5 4.5 PSO 0.1 0.9 0.9 SWEPCo 0.8 6.0 4.9

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2016
Lease Rental Costs	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Rockport Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments AEP (a) I&M (in millions) 2017 $ 147.8 $ 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 Later Years 147.2 73.6 Total Future Minimum Lease Payments $ 886.2 $ 443.1 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M.
Nuclear Fuel Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments I&M (in millions) 2017 $ 5.8 2018 2.4 Total Future Minimum Lease Payments $ 8.2
Appalachian Power Co [Member]
Lease Rental Costs	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Indiana Michigan Power Co [Member]
Lease Rental Costs	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Indiana Michigan Power Co [Member] | Rockport Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments AEP (a) I&M (in millions) 2017 $ 147.8 $ 73.9 2018 147.8 73.9 2019 147.8 73.9 2020 147.8 73.9 2021 147.8 73.9 Later Years 147.2 73.6 Total Future Minimum Lease Payments $ 886.2 $ 443.1 (a) AEP’s future minimum lease payments includes equal shares from AEGCo and I&M.
Indiana Michigan Power Co [Member] | Nuclear Fuel Lease [Member]
Future Minimum Lease Payments	Future Minimum Lease Payments I&M (in millions) 2017 $ 5.8 2018 2.4 Total Future Minimum Lease Payments $ 8.2
Ohio Power Co [Member]
Lease Rental Costs	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Public Service Co Of Oklahoma [Member]
Lease Rental Costs	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5
Southwestern Electric Power Co [Member]
Lease Rental Costs	Year Ended December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 224.9 $ 16.6 $ 90.5 $ 7.1 $ 5.0 $ 6.7 Amortization of Capital Leases 93.7 6.4 35.6 4.2 3.7 13.6 Interest on Capital Leases 18.9 3.5 3.7 0.5 0.6 5.1 Total Lease Rental Costs $ 337.5 $ 26.5 $ 129.8 $ 11.8 $ 9.3 $ 25.4 Year Ended December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 292.6 $ 16.4 $ 88.3 $ 7.6 $ 5.4 $ 6.7 Amortization of Capital Leases 108.5 5.6 40.7 3.9 3.5 13.7 Interest on Capital Leases 25.1 0.8 3.3 0.6 0.7 6.2 Total Lease Rental Costs $ 426.2 (a) $ 22.8 $ 132.3 $ 12.1 $ 9.6 $ 26.6 Year Ended December 31, 2014 AEP APCo I&M OPCo PSO SWEPCo (in millions) Net Lease Expense on Operating Leases $ 303.9 $ 18.3 $ 93.4 $ 6.6 $ 3.2 $ 5.5 Amortization of Capital Leases 109.4 5.5 44.4 5.7 4.2 14.9 Interest on Capital Leases 26.1 1.0 2.8 1.2 0.7 7.4 Total Lease Rental Costs $ 439.4 (a) $ 24.8 $ 140.6 $ 13.5 $ 8.1 $ 27.8 (a) Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
Property, Plant and Equipment and Related Obligations Under Capital Leases	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 146.3 $ 45.0 $ 26.4 $ — $ 10.0 $ 34.5 Other Property, Plant and Equipment 373.1 18.1 43.7 23.9 19.4 122.1 Total Property, Plant and Equipment 519.4 63.1 70.1 23.9 29.4 156.6 Accumulated Amortization 226.4 18.1 25.4 11.6 15.6 86.5 Net Property, Plant and Equipment Under Capital Leases $ 293.0 $ 45.0 $ 44.7 $ 12.3 $ 13.8 $ 70.1 Obligations Under Capital Leases: Noncurrent Liability $ 242.1 $ 38.2 $ 35.3 $ 8.1 $ 9.8 $ 65.5 Liability Due Within One Year 63.4 6.8 9.4 4.2 4.1 11.8 Total Obligations Under Capital Leases $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Property, Plant and Equipment Under Capital Leases: Generation $ 128.2 $ 43.4 $ 14.5 $ — $ 9.6 $ 34.5 Other Property, Plant and Equipment 439.3 17.6 68.2 23.4 18.6 165.1 Total Property, Plant and Equipment 567.5 61.0 82.7 23.4 28.2 199.6 Accumulated Amortization 214.1 15.6 19.7 10.2 13.6 91.3 Net Property, Plant and Equipment Under Capital Leases $ 353.4 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 108.3 Obligations Under Capital Leases: Noncurrent Liability $ 247.3 $ 39.1 $ 30.2 $ 9.3 $ 10.9 $ 75.6 Liability Due Within One Year 96.2 6.3 32.8 3.9 3.7 21.9 Total Obligations Under Capital Leases $ 343.5 $ 45.4 $ 63.0 $ 13.2 $ 14.6 $ 97.5
Future Minimum Lease Payments	Capital Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 81.3 $ 10.3 $ 15.2 $ 4.7 $ 4.7 $ 14.7 2018 65.0 9.3 9.5 3.8 3.4 13.7 2019 48.7 7.3 5.8 1.5 2.1 12.2 2020 39.3 6.5 5.3 1.1 1.5 10.4 2021 32.8 6.2 5.0 0.9 1.1 9.6 Later Years 118.7 23.7 27.6 1.5 2.6 33.1 Total Future Minimum Lease Payments 385.8 63.3 68.4 13.5 15.4 93.7 Less Estimated Interest Element 80.3 18.3 23.7 1.2 1.5 16.4 Estimated Present Value of Future Minimum Lease Payments $ 305.5 $ 45.0 $ 44.7 $ 12.3 $ 13.9 $ 77.3 Noncancelable Operating Leases AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 238.2 $ 16.2 $ 91.8 $ 9.3 $ 4.4 $ 6.1 2018 229.5 14.9 90.6 7.9 3.9 5.7 2019 221.0 13.5 89.5 6.4 3.4 5.4 2020 212.7 12.9 86.0 5.4 2.9 5.1 2021 197.6 10.5 81.6 4.5 1.9 4.6 Later Years 282.2 29.0 94.6 18.3 4.6 15.0 Total Future Minimum Lease Payments $ 1,381.2 $ 97.0 $ 534.1 $ 51.8 $ 21.1 $ 41.9
Maximum Potential Loss	Company Maximum Potential Loss (in millions) AEP $ 36.7 APCo 5.4 I&M 3.4 OPCo 5.8 PSO 3.0 SWEPCo 3.5

Financing Activities (Tables)

Financing Activities (Tables)	12 Months Ended
	Dec. 31, 2016
AEP Common Stock	Shares of AEP Common Stock Issued Held in Treasury Balance, December 31, 2013 508,113,964 20,336,592 Issued 1,625,195 — Balance, December 31, 2014 509,739,159 20,336,592 Issued 1,650,014 — Balance, December 31, 2015 511,389,173 20,336,592 Issued 659,347 — Balance, December 31, 2016 512,048,520 20,336,592
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information.
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1 (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 7 for additional information.
Dividend Payment Restrictions	APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9
Lines of Credit and Short-term Debt	December 31, 2016 2015 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Amount Interest Rate (a) (in millions) (in millions) Securitized Debt for Receivables (b) $ 673.0 0.70 % $ 675.0 0.30 % Commercial Paper 1,040.0 1.02 % 125.0 0.81 % Total Short-term Debt $ 1,713.0 $ 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	Years Ended December 31, 2016 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.70 % 0.30 % 0.22 % Net Uncollectible Accounts Receivable Written Off $ 23.7 $ 34.1 $ 40.1
Customer Accounts Receivable Managed Portfolio	December 31, 2016 2015 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 945.0 $ 924.8 Short-term – Securitized Debt of Receivables 673.0 675.0 Delinquent Securitized Accounts Receivable 42.7 48.3 Bad Debt Reserves Related to Securitization 27.7 17.5 Unbilled Receivables Related to Securitization 322.1 357.8
Appalachian Power Co [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information.
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1
Dividend Payment Restrictions	APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 —
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Indiana Michigan Power Co [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information.
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1
Dividend Payment Restrictions	APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 —
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Ohio Power Co [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information.
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1
Dividend Payment Restrictions	APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 —
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Public Service Co Of Oklahoma [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information.
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1
Dividend Payment Restrictions	APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 —
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8
Southwestern Electric Power Co [Member]
Long-term Debt	Weighted Average Interest Rate as of Interest Rate Ranges as of Outstanding as of December 31, December 31, December 31, Company Maturity 2016 2016 2015 2016 2015 AEP (in millions) Senior Unsecured Notes 2016-2046 4.90% 1.65%-8.13% 1.65%-8.13% $ 14,761.0 (e) $ 13,629.1 Pollution Control Bonds (a) 2016-2042 (b) 2.97% 0.69%-6.30% 0.01%-6.30% 1,725.1 1,784.8 Notes Payable – Nonaffiliated (c) 2016-2032 2.45% 1.456%-6.37% 0.925%-6.60% 326.9 264.7 Securitization Bonds 2016-2031 3.66% 0.88%-5.31% 0.88%-6.25% 1,705.0 2,024.0 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2016-2059 2.08% 1.15%-13.718% 1.15%-13.718% 1,606.9 1,604.5 Total Long-term Debt Outstanding $ 20,391.2 (e) $ 19,572.7 APCo Senior Unsecured Notes 2017-2045 5.39% 3.40%-7.00% 3.40%-7.00% $ 2,972.4 $ 2,970.4 Pollution Control Bonds (a) 2016-2042 (b) 1.96% 0.69%-5.38% 0.01%-5.375% 615.8 616.5 Securitization Bonds 2024-2031 2.91% 2.008%-3.772% 2.008%-3.772% 318.9 341.5 Other Long-term Debt 2019-2026 2.27% 2.06%-13.718% 13.718% 126.8 2.3 Total Long-term Debt Outstanding $ 4,033.9 $ 3,930.7 I&M Senior Unsecured Notes 2019-2046 5.49% 3.20%-7.00% 3.20%-7.00% $ 1,512.8 $ 1,117.0 Pollution Control Bonds (a) 2016-2025 (b) 2.04% 0.74%-4.625% 0.01%-4.625% 225.4 225.1 Notes Payable – Nonaffiliated (c) 2016-2021 1.63% 1.456%-1.81% 0.925%-2.12% 251.4 175.5 Spent Nuclear Fuel Obligation (d) 266.3 265.6 Other Long-term Debt 2018-2025 2.43% 2.15%-6.00% 1.81%-6.00% 215.5 216.8 Total Long-term Debt Outstanding $ 2,471.4 $ 2,000.0 OPCo Senior Unsecured Notes 2016-2035 5.98% 5.375%-6.60% 5.375%-6.60% $ 1,590.2 $ 1,938.9 Pollution Control Bonds 2038 5.80% 5.80% 5.80% 32.3 32.2 Securitization Bonds 2018-2020 1.75% 0.958%-2.049% 0.958%-2.049% 140.2 185.3 Other Long-term Debt 2028 1.15% 1.15% 1.15% 1.2 1.3 Total Long-term Debt Outstanding $ 1,763.9 $ 2,157.7 PSO Senior Unsecured Notes 2016-2046 4.80% 3.05%-6.625% 3.17%-6.625% $ 1,143.2 $ 1,142.7 Pollution Control Bonds (a) 2020 4.45% 4.45% 4.45% 12.6 12.6 Other Long-term Debt 2016-2027 1.96% 1.92%-3.00% 1.587%-3.00% 130.2 130.8 Total Long-term Debt Outstanding $ 1,286.0 $ 1,286.1 SWEPCo Senior Unsecured Notes 2017-2045 4.86% 2.75%-6.45% 3.55%-6.45% $ 2,359.2 $ 1,961.0 Pollution Control Bonds (a) 2018-2019 3.62% 1.60%-4.95% 1.60%-4.95% 134.9 134.5 Notes Payable – Nonaffiliated (c) 2024-2032 5.17% 4.58%-6.37% 4.58%-6.37% 75.3 78.6 Other Long-term Debt 2017-2023 2.48% 2.346%-4.28% 1.82% 109.7 99.4 Total Long-term Debt Outstanding $ 2,679.1 $ 2,273.5 (a) For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series. (b) Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets. (c) Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates. (d) Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6 ). (e) 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 7 for additional information.
Long-term Debt 5-Year Maturity	AEP APCo I&M OPCo PSO SWEPCo (in millions) 2017 $ 3,013.4 (a) $ 503.1 $ 209.3 $ 46.4 $ 0.5 $ 353.7 2018 1,987.0 194.0 369.3 397.0 0.5 385.4 2019 2,287.1 235.5 518.8 48.0 375.4 457.2 2020 486.4 140.3 10.5 0.1 13.2 3.7 2021 1,308.4 393.0 3.9 500.1 250.5 3.7 After 2021 11,437.3 2,602.0 1,373.7 783.0 653.0 1,491.9 Principal Amount 20,519.6 (a) 4,067.9 2,485.5 1,774.6 1,293.1 2,695.6 Unamortized Discount, Net and Debt Issuance Costs (128.4 ) (a) (34.0 ) (14.1 ) (10.7 ) (7.1 ) (16.5 ) Total Long-term Debt Outstanding $ 20,391.2 (a) $ 4,033.9 $ 2,471.4 $ 1,763.9 $ 1,286.0 $ 2,679.1
Dividend Payment Restrictions	APCo I&M OPCo PSO SWEPCo Other AEP Subsidiaries AEP (in millions) Restricted Retained Earnings $ — $ 288.5 $ — $ 127.5 $ 528.9 $ 590.0 $ 1,534.9
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Year Ended December 31, 2016 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2016 Limit (in millions) APCo $ 286.9 $ 25.7 $ 148.0 $ 24.8 $ (55.5 ) $ 600.0 I&M 369.1 97.6 129.9 19.5 (202.7 ) 500.0 OPCo 227.9 379.2 116.6 182.4 24.2 400.0 PSO 52.0 205.4 12.9 48.1 (52.0 ) 300.0 SWEPCo 249.4 313.3 171.8 267.7 167.8 350.0 Year Ended December 31, 2015 : Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool December 31, 2015 Limit (in millions) APCo $ 211.2 $ 694.8 $ 82.0 $ 79.0 $ (155.4 ) $ 600.0 I&M 297.3 13.5 152.6 13.5 (282.6 ) 500.0 OPCo — 367.5 — 266.6 331.1 400.0 PSO 165.9 152.5 113.1 86.8 80.6 300.0 SWEPCo 112.5 299.9 48.1 103.4 (58.3 ) 350.0
Nonutility Money Pool Activity	Maximum Average Loans Loans Loans to the to the to the Nonutility Nonutility Nonutility Money Pool as of Money Pool Money Pool December 31, 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	Years Ended December 31, 2016 2015 2014 Maximum Interest Rate 1.02 % 0.87 % 0.59 % Minimum Interest Rate 0.69 % 0.37 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Years Ended December 31, Average Interest Rate for Funds Loaned to the Utility Money Pool for Years Ended December 31, Company 2016 2015 2014 2016 2015 2014 APCo 0.80 % 0.53 % 0.29 % 0.82 % 0.47 % 0.29 % I&M 0.80 % 0.49 % 0.31 % 0.80 % 0.48 % 0.30 % OPCo 0.85 % — % 0.27 % 0.74 % 0.48 % 0.34 % PSO 0.96 % 0.49 % 0.29 % 0.83 % 0.48 % — % SWEPCo 0.79 % 0.53 % 0.29 % 0.90 % 0.48 % 0.32 %
Maximum, Minimum and Average Interest Rates for Funds Borrowed from and Loaned to the Nonutility Money Pool	Maximum Minimum Average Interest Rate Interest Rate Interest Rate for Funds for Funds for Funds Loaned to Loaned to Loaned to Year Ended the Nonutility the Nonutility the Nonutility December 31, Money Pool Money Pool Money Pool 2016 1.02 % 0.69 % 0.82 %
Interest Expense Incurred by Registrant Subsidiaries' for amounts borrowed from the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.2 $ 0.2 $ — I&M 0.9 0.8 0.1 OPCo 0.4 — — PSO — 0.1 0.3 SWEPCo 1.0 0.1 0.2
Interest Income Earned by Registrant Subsidiaries' for Amounts Advanced to the Utility Money Pool	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 0.2 $ 0.4 $ 0.3 I&M 0.2 0.1 0.1 OPCo 0.9 1.3 0.2 PSO 0.4 0.4 — SWEPCo 0.6 0.4 —
Accounts Receivable and Accrued Unbilled Revenues	December 31, Company 2016 2015 (in millions) APCo $ 142.0 $ 135.4 I&M 136.7 134.8 OPCo 388.3 351.4 PSO 110.4 116.1 SWEPCo 130.9 151.8
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 6.7 $ 7.6 $ 8.9 I&M 7.1 8.4 7.9 OPCo 28.9 30.7 28.8 PSO 6.2 5.8 5.9 SWEPCo 6.9 7.0 6.8
Proceeds on Sale of Receivables to AEP Credit	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1,412.5 $ 1,453.8 $ 1,519.3 I&M 1,596.2 1,553.0 1,488.6 OPCo 2,633.0 2,569.4 2,647.6 PSO 1,269.3 1,326.1 1,321.1 SWEPCo 1,531.7 1,597.8 1,655.8

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Share-based Compensation [Abstract]
Performance Units and Reinvested Dividends on Outstanding Performance Units	Years Ended December 31, Performance Units 2016 2015 2014 Awarded Units (in thousands) 597.4 575.0 16.9 Weighted Average Unit Fair Value at Grant Date $ 62.77 $ 59.19 $ 49.73 Vesting Period (in years) 3 3 3 Performance Units and AEP Career Shares (Reinvested Dividends Portion) Years Ended December 31, 2016 2015 2014 Awarded Units (in thousands) 89.2 103.6 98.9 Weighted Average Fair Value at Grant Date $ 63.83 $ 54.35 $ 53.35 Vesting Period (in years) (a) (a) (a) (a) The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP career shares vest immediately when the dividend is awarded but are not paid in cash until after the participant’s AEP employment ends.
Summary of Performance Scores and Performance Units Earned	Years Ended December 31, Performance Units 2016 2015 2014 Certified Performance Score 163.9 % 176.3 % 147.8 % Performance Units Earned 1,111,966 1,202,107 889,697 Performance Units Mandatorily Deferred as AEP Career Shares 9,963 41,707 40,831 Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program 51,684 54,074 39,526 Performance Units to be Paid in Cash 1,050,319 1,106,326 809,340
Summary of Cash Payouts for Performance Units and Career Shares	Years Ended December 31, Performance Units and AEP Career Shares 2016 2015 2014 (in millions) Cash Payouts for Performance Units $ 62.7 $ 48.1 $ 29.3 Cash Payouts for AEP Career Share Distributions 9.1 3.0 4.3
Summary of Units Awarded and Fair Value of Restricted Stock Units	Years Ended December 31, Restricted Stock Units 2016 2015 2014 Awarded Units (in thousands) 242.0 397.5 64.1 Weighted Average Grant Date Fair Value $ 62.88 $ 58.56 $ 50.36
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	Years Ended December 31, Restricted Stock Units 2016 2015 2014 (in millions) Fair Value of Restricted Stock Units Vested $ 16.4 $ 18.3 $ 18.7 Intrinsic Value of Restricted Stock Units Vested (a) 21.0 24.2 24.9 (a) Intrinsic value is calculated as market price at exercise date.
Status of Nonvested Restricted Shares and Restricted Stock Units	Nonvested Restricted Stock Units Shares/Units Weighted Average Grant Date Fair Value (in thousands) Nonvested as of January 1, 2016 721.3 $ 52.48 Granted 242.0 62.88 Vested (326.7 ) 50.07 Forfeited (33.0 ) 55.81 Nonvested as of December 31, 2016 603.6 57.54
Stock Unit Accumulation Plan for Non-employee Directors	Years Ended December 31, Stock Unit Accumulation Plan for Non-Employee Directors 2016 2015 2014 Awarded Units (in thousands) 19.1 24.9 25.4 Weighted Average Grant Date Fair Value $ 64.96 $ 55.46 $ 54.08
Compensation Cost and Actual Tax Benefit Realized for Tax Deductions from Compensation Cost for Share-based Payment Arrangements	Years Ended December 31, Share-based Compensation Plans 2016 2015 2014 (in millions) Compensation Cost for Share-based Payment Arrangements (a) $ 66.5 $ 63.8 $ 85.4 Actual Tax Benefit Realized 23.3 22.3 29.9 Total Compensation Cost Capitalized 20.8 20.3 23.1 (a) Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Appalachian Power Co [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Agreement	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 103.2 $ 92.7 $ 84.7 I&M 53.0 38.0 39.7 OPCo 143.6 81.0 17.0
Barging, Urea Transloading and Other Services	Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ 14.8 $ 16.1 $ 22.7 AGR 0.3 4.9 5.2 APCo 36.9 37.7 36.1 KPCo 5.3 4.6 5.0 WPCo 4.8 — — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — 15.5 25.3
Central Machine Shop	Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1
Affiliate Railcar Agreement	December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 —
Ownership and Investment in OVEC	December 31, 2016 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4
Purchased Power from OVEC	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 88.0 $ 87.2 $ 96.9 I&M 44.0 43.7 48.5 OPCo 111.7 110.8 123.1
Related Party Sales of Property	Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0
Indiana Michigan Power Co [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Agreement	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 103.2 $ 92.7 $ 84.7 I&M 53.0 38.0 39.7 OPCo 143.6 81.0 17.0
Coal Transloading	Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 12.8 $ 15.8 $ 16.2
Railcar Maintenance	Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 1.7 $ 2.0 $ 2.5 PSO 0.6 0.2 0.3 SWEPCo 3.3 2.8 3.3
Barging, Urea Transloading and Other Services	Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ 14.8 $ 16.1 $ 22.7 AGR 0.3 4.9 5.2 APCo 36.9 37.7 36.1 KPCo 5.3 4.6 5.0 WPCo 4.8 — — AEP River Operations LLC – (Nonutility Subsidiary of AEP) — 15.5 25.3
Central Machine Shop	Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1
Affiliate Railcar Agreement	December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 —
Ownership and Investment in OVEC	December 31, 2016 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4
Purchased Power from OVEC	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 88.0 $ 87.2 $ 96.9 I&M 44.0 43.7 48.5 OPCo 111.7 110.8 123.1
Related Party Sales of Property	Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0
Ohio Power Co [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Agreement	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 103.2 $ 92.7 $ 84.7 I&M 53.0 38.0 39.7 OPCo 143.6 81.0 17.0
Ownership and Investment in OVEC	December 31, 2016 Company Ownership Investment (in millions) Parent 39.17 % $ 4.0 OPCo 4.30 % 0.4 Total 43.47 % $ 4.4
Purchased Power from OVEC	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 88.0 $ 87.2 $ 96.9 I&M 44.0 43.7 48.5 OPCo 111.7 110.8 123.1
Related Party Sales of Property	Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0
Public Service Co Of Oklahoma [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Coordination Agreement	Years Ended December 31, Company 2016 2015 2014 (in millions) PSO $ 19.6 $ 15.0 $ 14.1 SWEPCo (19.6 ) (15.0 ) (14.1 )
Railcar Maintenance	Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 1.7 $ 2.0 $ 2.5 PSO 0.6 0.2 0.3 SWEPCo 3.3 2.8 3.3
Central Machine Shop	Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1
Affiliate Railcar Agreement	December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 —
Related Party Sales of Property	Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0
Southwestern Electric Power Co [Member]
Affiliated Revenues	Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Sales to East Affiliates $ 126.0 $ — $ — $ — $ — Direct Sales to West Affiliates — — — — 3.7 Auction Sales to OPCo (a) 9.2 12.0 — — — Direct Sales to AEPEP — — — — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 1.3 12.2 (2.0 ) (1.7 ) 19.4 Other Revenues 5.6 2.0 19.3 4.3 1.6 Total Affiliated Revenues $ 142.1 $ 26.2 $ 17.3 $ 2.6 $ 24.5 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Sales to East Affiliates $ 132.1 $ — $ — $ — $ — Auction Sales to OPCo (a) 10.6 17.1 — — — Direct Sales to AEPEP — — 29.7 — (0.2 ) Transmission Agreement and Transmission Coordination Agreement Sales 0.7 8.4 35.5 0.2 15.2 Other Revenues 4.4 1.9 18.9 4.4 1.6 Total Affiliated Revenues $ 147.8 $ 27.4 $ 84.1 $ 4.6 $ 16.6 Related Party Revenues APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Sales under Interconnection Agreement (b) $ 0.2 $ 0.5 $ 1.1 $ — $ — Direct Sales to East Affiliates 141.7 — — 3.8 10.1 Direct Sales to West Affiliates 0.6 0.4 — — 0.3 Direct Sales to AEPEP — — 44.1 — — Transmission Agreement and Transmission Coordination Agreement Sales (1.6 ) 1.7 104.1 — 14.1 Other Revenues 3.6 1.6 15.9 3.3 1.8 Total Affiliated Revenues $ 144.5 $ 4.2 $ 165.2 $ 7.1 $ 26.3 (a) Refer to the Ohio Auctions section below for further information regarding these amounts. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Affiliated Purchases	Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2016 Direct Purchases from West Affiliates — — — 3.7 — Auction Purchases from AEPEP (a) — — 110.1 — — Auction Purchases from AEP Energy (a) — — 7.7 — — Auction Purchases from AEPSC (a) — — 24.1 — — Direct Purchases from AEGCo — 228.6 — — — Total Affiliated Purchases $ — $ 228.6 $ 141.9 $ 3.7 $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2015 Direct Purchases from AGR(c) $ — $ — $ 269.2 $ — $ — Auction Purchases from AEPEP (a) — — 225.2 — — Auction Purchases from AEPSC (a) — — 32.7 — — Direct Purchases from AEGCo — 232.1 — — — Total Affiliated Purchases $ — $ 232.1 $ 527.1 $ — $ — Related Party Purchases APCo I&M OPCo PSO SWEPCo (in millions) Year Ended December 31, 2014 Purchases under Interconnection Agreement (b) $ 4.7 $ 1.6 $ 0.1 $ — $ — Direct Purchases from East Affiliates — — — 1.0 — Direct Purchases from West Affiliates — — — 10.0 3.8 Direct Purchases from AGR(c) — — 1,305.2 — — Direct Purchases from AEPEP — — 44.4 — — Direct Purchases from AEGCo — 268.4 — — — Total Affiliated Purchases $ 4.7 $ 270.0 $ 1,349.7 $ 11.0 $ 3.8 (a) Refer to the Ohio Auctions section below for further information regarding this amount. (b) Includes December 2013 true-up activity subsequent to agreement termination.
Transmission Coordination Agreement	Years Ended December 31, Company 2016 2015 2014 (in millions) PSO $ 19.6 $ 15.0 $ 14.1 SWEPCo (19.6 ) (15.0 ) (14.1 )
Railcar Maintenance	Years Ended December 31, Company 2016 2015 2014 (in millions) I&M $ 1.7 $ 2.0 $ 2.5 PSO 0.6 0.2 0.3 SWEPCo 3.3 2.8 3.3
Central Machine Shop	Years Ended December 31, Company 2016 2015 2014 (in millions) AEGCo $ — $ 0.1 $ 0.1 AGR 2.0 2.7 2.8 I&M 2.9 2.5 1.7 KPCo 1.5 1.3 1.2 PSO 0.5 0.2 0.3 SWEPCo 0.9 0.8 0.1
Affiliate Railcar Agreement	December 31, 2016 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.3 0.8 PSO 0.3 — 0.2 SWEPCo 0.9 0.3 — December 31, 2015 Billing Company Billed Company I&M PSO SWEPCo APCo $ — $ 0.3 $ 0.3 I&M — 0.4 1.2 PSO 0.6 — 0.6 SWEPCo 1.8 0.6 —
Related Party Sales of Property	Sales Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 4.5 $ 9.4 $ 3.0 I&M 5.2 3.0 1.3 OPCo 1.9 2.4 0.5 PSO 7.5 7.1 0.5 SWEPCo 1.0 0.8 1.2
Related Party Purchases of Property	Purchases Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 1.5 $ 8.6 $ 0.9 I&M 2.7 8.1 1.4 OPCo 1.7 2.1 1.9 PSO 3.2 0.6 2.1 SWEPCo 6.5 7.4 4.0

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	12 Months Ended
	Dec. 31, 2016
Consolidated Assets And Liabilities Of Variable Interest Entities	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy AEP Renewables (in millions) ASSETS Current Assets $ 945.7 $ 184.8 $ 170.6 $ 16.3 $ — Net Property, Plant and Equipment — — — 313.0 130.4 Other Noncurrent Assets 10.3 1,149.4 (a) 1.1 5.4 9.0 Total Assets $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 LIABILITIES AND EQUITY Current Liabilities $ 877.4 $ 251.9 $ 31.8 $ 31.7 $ 126.7 Noncurrent Liabilities 0.6 1,064.2 97.3 134.4 11.3 Equity 78.0 18.1 42.6 168.6 1.4 Total Liabilities and Equity $ 956.0 $ 1,334.2 $ 171.7 $ 334.7 $ 139.4 (a) Includes an intercompany item eliminated in consolidation of $61.1 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Other Consolidated VIEs AEP Credit AEP Texas Transition Funding Protected Cell of EIS Transource Energy (in millions) ASSETS Current Assets $ 925.7 $ 234.1 $ 165.3 $ 10.8 Net Property, Plant and Equipment — — — 227.2 Other Noncurrent Assets 6.4 1,365.7 (a) 1.9 5.5 Total Assets $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 LIABILITIES AND EQUITY Current Liabilities $ 855.1 $ 291.7 $ 41.8 $ 36.6 Noncurrent Liabilities 0.3 1,290.0 83.9 113.0 Equity 76.7 18.1 41.5 93.9 Total Liabilities and Equity $ 932.1 $ 1,599.8 $ 167.2 $ 243.5 (a) 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	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3
Appalachian Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 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 December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million .
Indiana Michigan Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3
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	December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 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 December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million .
Ohio Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3
Ohio Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 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 December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million .
Public Service Co Of Oklahoma [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3
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	December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 16.4 16.4
Southwestern Electric Power Co [Member] | Billings from AEP Service Corporation [Member]
Billings from Significant Variable Interest	Years Ended December 31, Company 2016 2015 2014 (in millions) APCo $ 244.2 $ 227.5 $ 216.5 I&M 147.7 139.5 133.2 OPCo 181.1 177.8 169.0 PSO 111.0 107.3 101.4 SWEPCo 147.0 141.4 140.3
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	December 31, 2016 2015 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) APCo $ 36.7 $ 36.7 $ 25.8 $ 25.8 I&M 24.2 24.2 16.6 16.6 OPCo 28.1 28.1 23.3 23.3 PSO 16.0 16.0 12.6 12.6 SWEPCo 21.8 21.8 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 December 31, 2015 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 61.7 $ 91.1 $ 31.2 $ 18.5 Net Property, Plant and Equipment 147.0 159.9 — — Other Noncurrent Assets 61.8 84.6 162.0 (a) 332.0 (b) Total Assets $ 270.5 $ 335.6 $ 193.2 $ 350.5 LIABILITIES AND EQUITY Current Liabilities $ 47.7 $ 84.8 $ 47.3 $ 27.1 Noncurrent Liabilities 222.3 250.8 144.6 321.5 Equity 0.5 — 1.3 1.9 Total Liabilities and Equity $ 270.5 $ 335.6 $ 193.2 $ 350.5 (a) Includes an intercompany item eliminated in consolidation of $76.1 million . (b) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2016 Registrant Subsidiaries SWEPCo Sabine I&M DCC Fuel OPCo APCo (in millions) ASSETS Current Assets $ 60.2 $ 135.5 $ 30.3 $ 20.2 Net Property, Plant and Equipment 112.0 233.9 — — Other Noncurrent Assets 89.8 116.2 117.1 (a) 309.0 (b) Total Assets $ 262.0 $ 485.6 $ 147.4 $ 329.2 LIABILITIES AND EQUITY Current Liabilities $ 26.3 $ 131.3 $ 47.5 $ 27.3 Noncurrent Liabilities 235.3 354.3 98.6 300.6 Equity 0.4 — 1.3 1.3 Total Liabilities and Equity $ 262.0 $ 485.6 $ 147.4 $ 329.2 (a) Includes an intercompany item eliminated in consolidation of $55 million . (b) Includes an intercompany item eliminated in consolidation of $3.7 million .
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Companys Investment In Joint Venture	December 31, 2016 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 15.7 15.7 7.7 7.7 SWEPCo’s Guarantee of Debt — 91.3 — 82.9 Total Investment in DHLC $ 23.3 $ 114.6 $ 15.3 $ 98.2
PATH West Virginia Transmission Co, LLC [Member]
Companys Investment In Joint Venture	December 31, 2016 2015 As Reported on the Balance Sheet Maximum Exposure As Reported on Maximum Exposure (in millions) Capital Contribution from Parent $ 18.8 $ 18.8 $ 18.8 $ 18.8 Retained Earnings (2.3 ) (2.3 ) 2.2 2.2 Total Investment in PATH-WV $ 16.5 $ 16.5 $ 21.0 $ 21.0

Property, Plant and Equipment54

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Property, Plant and Equipment	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 .
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Appalachian Power Co [Member]
Property, Plant and Equipment	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
Depreciation, Depletion and Amortization	APCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 3.1% 35 - 121 3.1% 35 - 121 3.1% 40 - 121 Transmission 1.5% 15 - 68 1.6% 15 - 68 1.7% 15 - 87 Distribution 3.7% 10 - 57 3.6% 10 - 57 3.5% 13 - 57 Other 6.0% 5 - 55 8.3% 5 - 55 6.9% 24 - 55
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 .
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9
Indiana Michigan Power Co [Member]
Property, Plant and Equipment	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
Depreciation, Depletion and Amortization	I&M 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 59 - 132 2.5% 59 - 132 2.0% 59 - 132 Transmission 1.7% 50 - 75 1.7% 50 - 75 1.7% 50 - 75 Distribution 2.8% 10 - 70 2.8% 10 - 70 2.8% 15 - 70 Other 8.6% 5 - 45 11.8% 5 - 45 6.1% 14 - 45
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 .
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Ohio Power Co [Member]
Property, Plant and Equipment	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
Depreciation, Depletion and Amortization	OPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Transmission 2.3% 39 - 60 2.3% 39 - 60 2.3% 39 - 60 Distribution 2.8% 7 - 57 2.8% 7 - 57 2.7% 7 - 57 Other 5.9% 5 - 50 7.2% 5 - 50 7.0% 7 - 50
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 .
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9 Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9
Public Service Co Of Oklahoma [Member]
Property, Plant and Equipment	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
Depreciation, Depletion and Amortization	PSO 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.4% 35 - 85 1.7% 35 - 70 1.7% 35 - 70 Transmission 2.2% 45 - 100 1.9% 40 - 75 1.9% 40 - 75 Distribution 2.7% 27 - 156 2.5% 7 - 65 2.4% 30 - 65 Other 6.4% 5 - 84 4.6% 5 - 40 4.1% 5 - 40
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 .
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9 Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Southwestern Electric Power Co [Member]
Property, Plant and Equipment	December 31, 2016 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,703.9 (b) $ 6,332.8 $ 4,056.1 $ — $ 1,559.3 $ 4,607.6 (b) Transmission 16,658.6 2,796.9 1,472.8 2,319.2 832.8 1,584.2 Distribution 18,898.2 3,569.1 1,899.3 4,457.2 2,322.4 2,020.6 Other 2,902.0 345.1 507.7 433.4 227.3 399.3 CWIP 3,072.2 (b) 390.3 654.2 221.5 148.2 113.7 (b) Less: Accumulated Depreciation 16,101.5 3,631.5 2,989.9 2,115.1 1,272.7 2,411.5 Total Regulated Property, Plant and Equipment - Net 45,133.4 9,802.7 5,600.2 5,316.2 3,817.3 6,313.9 Nonregulated Property, Plant and Equipment - Net 505.9 23.1 27.3 9.4 5.9 115.6 Total Property, Plant and Equipment - Net $ 45,639.3 (a) $ 9,825.8 $ 5,627.5 $ 5,325.6 $ 3,823.2 $ 6,429.5 December 31, 2015 AEP APCo I&M OPCo PSO SWEPCo (in millions) Regulated Property, Plant and Equipment Generation $ 19,082.8 (b) $ 6,200.8 $ 3,841.7 $ — $ 1,302.6 $ 3,943.5 (b) Transmission 14,219.0 2,408.1 1,406.9 2,235.6 815.4 1,387.8 Distribution 18,046.9 3,402.5 1,790.8 4,287.7 2,206.7 1,957.3 Other 3,066.7 310.1 511.6 397.8 400.5 582.2 CWIP 3,774.4 (b) 475.1 519.8 171.9 315.3 744.7 (b) Less: Accumulated Depreciation 16,076.9 3,395.5 2,908.3 2,047.9 1,352.5 2,445.0 Total Regulated Property, Plant and Equipment - Net 42,112.9 9,401.1 5,162.5 5,045.1 3,688.0 6,170.5 Nonregulated Property, Plant and Equipment - Net 4,020.3 23.3 41.0 9.6 5.2 150.6 Total Property, Plant and Equipment - Net $ 46,133.2 $ 9,424.4 $ 5,203.5 $ 5,054.7 $ 3,693.2 $ 6,321.1 (a) Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information. (b) AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
Depreciation, Depletion and Amortization	SWEPCo 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges Annual Composite Depreciation Rate Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% 40 - 70 2.2% 40 - 70 2.2% 40 - 70 Transmission 2.2% 50 - 70 2.3% 50 - 70 2.2% 50 - 70 Distribution 2.6% 25 - 65 2.6% 25 - 65 2.7% 25 - 65 Other 6.8% 5 - 51 5.5% 5 - 51 4.8% 7 - 51
Asset Retirement Obligation (ARO)	Company ARO as of December 31, 2015 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2016 (in millions) AEP (c)(d)(e)(f) $ 1,916.3 $ 91.3 $ 0.8 $ (139.9 ) (g) $ 66.4 $ 1,934.9 APCo (c)(f) 140.2 7.6 — (35.3 ) 14.6 127.1 I&M (c)(d)(f) 1,253.8 55.6 — (62.6 ) (g) 11.3 1,258.1 OPCo (f) 1.4 0.1 0.2 — — 1.7 PSO (c)(f) 47.8 3.0 0.1 (1.0 ) 3.5 53.4 SWEPCo (c)(e)(f) 125.4 7.0 0.2 (8.3 ) 32.2 156.5 Company ARO as of December 31, 2014 Accretion Expense Liabilities Incurred Liabilities Settled Revisions in Cash Flow Estimates ARO as of December 31, 2015 (in millions) AEP (c)(d)(e)(f) $ 2,019.6 $ 101.4 $ 58.0 $ (147.2 ) (a) $ (115.5 ) (b) $ 1,916.3 APCo (c)(f) 148.4 8.3 — (34.0 ) 17.5 140.2 I&M (c)(d)(f) 1,342.5 64.3 — (5.7 ) (147.3 ) 1,253.8 OPCo (f) 1.4 — — — — 1.4 PSO (c)(f) 38.1 2.6 5.6 (0.4 ) 1.9 47.8 SWEPCo (c)(e)(f) 94.4 5.9 17.1 (5.0 ) 13.0 125.4 (a) Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7 . (b) Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party. (c) Includes ARO related to ash disposal facilities. (d) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015 , respectively. (e) Includes ARO related to Sabine and DHLC. (f) Includes ARO related to asbestos removal. (g) Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7 .
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization	Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 113.2 $ 131.9 $ 102.9 APCo 11.7 13.8 7.1 I&M 15.3 11.6 18.9 OPCo 6.0 8.8 6.9 PSO 6.2 8.8 3.1 SWEPCo 11.0 26.4 11.9 Years Ended December 31, Company 2016 2015 2014 (in millions) AEP $ 51.7 $ 61.3 $ 44.5 APCo 6.3 6.9 3.8 I&M 7.2 5.0 8.0 OPCo 3.3 4.8 4.4 PSO 3.4 5.0 1.8 SWEPCo 6.9 14.8 6.9
Jointly-owned Electric Facilities	Registrant’s Share as of December 31, 2016 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 0.1 $ 1.3 $ — J.M. Stuart Generating Station (b) Coal 26.0 % — 0.8 — Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % — 0.3 — Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 334.8 5.0 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 454.8 1.3 246.0 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Transmission NA (d) 62.4 0.5 45.1 Total $ 3,458.2 $ 18.8 $ 1,110.1 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 936.1 $ 125.8 $ 535.1 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 105.2 $ 0.5 $ 59.4 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 334.8 $ 5.0 $ 207.5 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 362.4 3.7 73.5 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 586.4 5.7 399.5 Turk Generating Plant (j) Coal 73.3 % 1,657.3 0.2 138.5 Total $ 2,940.9 $ 14.6 $ 819.0 Registrant’s Share as of December 31, 2015 Fuel Type Percent of Ownership Utility Plant in Service Construction Work in Progress Accumulated Depreciation (in millions) AEP Conesville Generating Station, Unit 4 (a) (k) Coal 43.5 % $ 337.4 $ 2.4 $ 76.1 J.M. Stuart Generating Station (b) Coal 26.0 % 565.5 12.9 221.8 Wm. H. Zimmer Generating Station (c) (k) Coal 25.4 % 815.5 6.4 421.7 Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % 332.4 3.9 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Oklaunion Generating Station, Unit 1 (h) Coal 70.3 % 445.5 7.2 236.2 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Transmission NA (d) 68.5 0.4 48.1 Total $ 4,917.3 $ 239.6 $ 1,773.0 I&M Rockport Generating Plant (e)(f)(g) Coal 50.0 % $ 926.7 $ 58.5 $ 512.4 PSO Oklaunion Generating Station, Unit 1 (h) Coal 15.6 % $ 103.0 $ 1.8 $ 58.2 SWEPCo Dolet Hills Generating Station, Unit 1 (i) Lignite 40.2 % $ 332.4 $ 3.9 $ 205.9 Flint Creek Generating Station, Unit 1 (j) Coal 50.0 % 131.4 195.0 70.0 Pirkey Generating Station, Unit 1 (j) Lignite 85.9 % 572.1 5.9 389.1 Turk Generating Plant (j) Coal 73.33 % 1,649.0 5.5 104.1 Total $ 2,684.9 $ 210.3 $ 769.1 (a) Operated by AGR. See the “Impairments” section of Note 7 . (b) Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7 . (c) Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7 . (d) Varying percentages of ownership. (e) Operated by I&M. (f) Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13 . (g) AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2. (h) Operated by PSO, which owns 15.6% . Also jointly-owned ( 54.7% ) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7 . (i) Operated by CLECO, a non-affiliated company. (j) Operated by SWEPCo. (k) In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition. NA Not applicable.
Regulated Operation [Member]
Depreciation, Depletion and Amortization	AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.1% - 4.0% 35 - 132 0.4% - 3.1% 35 - 132 1.7% - 3.5% 31 - 132 Transmission 1.5% - 2.7% 15 - 100 1.4% - 2.7% 15 - 81 1.4% - 2.7% 15 - 87 Distribution 2.6% - 3.7% 7 - 156 2.5% - 3.7% 7 - 75 2.4% - 3.7% 7 - 75 Other 3.1% - 8.6% 5 - 84 2.9% - 11.8% 5 - 75 2.1% - 8.6% 5 - 75
Unregulated Operation [Member]
Depreciation, Depletion and Amortization	AEP 2016 2015 2014 Functional Class of Property Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges Annual Composite Depreciation Rate Ranges Depreciable Life Ranges (in years) (in years) (in years) Generation 2.8% - 17.2% 40 - 66 2.5% - 3.4% 35 - 66 2.6% - 3.4% 35 - 66 Transmission 2.3% 43 - 55 2.3% 43 - 55 2.3% 43 - 55 Distribution 1.3% 40 50 —% 0 - 0 —% 0 - 0 Other 9.1% 5 - 50 (a) 2.7% 5 - 50 (a) 17.1% 25 - 50 (a) (a) SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.

Unaudited Quarterly Financial55

Unaudited Quarterly Financial Information (Tables)	12 Months Ended
	Dec. 31, 2016
Schedule of Quarterly Financial Information	2016 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings (Loss) Attributable to AEP Common Shareholders $ 501.2 $ 502.1 $ (765.8 ) (a) $ 373.4 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.02 1.03 (1.56 ) (a) 0.76 Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations (c) — (0.01 ) — — Total Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders (b) 1.02 1.02 (1.56 ) (a) 0.76 2015 Quarterly Periods Ended March 31 June 30 September 30 December 31 Earnings Attributable to AEP Common Shareholders $ 629.2 $ 430.0 $ 518.3 $ 469.6 Basic Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Basic Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Basic Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 Diluted Earnings per Share Attributable to AEP Common Shareholders from Continuing Operations (b) 1.27 0.88 1.04 0.41 Diluted Earnings per Share Attributable to AEP Common Shareholders from Discontinued Operations (d) 0.02 — 0.02 0.54 Total Diluted Earnings per Share Attributable to AEP Common Shareholders (b) 1.29 0.88 1.06 0.95 (a) Relates to impairments for Merchant Generating Assets (see Note 7 ). (b) Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding. (c) Relates to final accounting adjustment for sale of AEPRO (see Note 7 ). (d) Relates to sale of AEPRO (see Note 7 ). Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ).
Appalachian Power Co [Member]
Schedule of Quarterly Financial Information	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ).
Indiana Michigan Power Co [Member]
Schedule of Quarterly Financial Information	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ).
Ohio Power Co [Member]
Schedule of Quarterly Financial Information	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ).
Public Service Co Of Oklahoma [Member]
Schedule of Quarterly Financial Information	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ).
Southwestern Electric Power Co [Member]
Schedule of Quarterly Financial Information	Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2016 Total Revenues $ 4,044.9 $ 820.0 $ 532.7 $ 763.6 $ 274.3 $ 379.0 Operating Income 892.9 244.4 115.8 134.0 35.8 51.4 Income from Continuing Operations 503.1 — — — — — Net Income 503.1 126.3 74.7 70.2 15.7 24.5 June 30, 2016 Total Revenues $ 3,892.9 $ 673.5 $ 522.4 $ 730.8 $ 300.2 $ 427.0 Operating Income 866.2 158.3 94.8 138.6 59.0 85.9 Income from Continuing Operations 506.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (2.5 ) (a) — — — — — Net Income 503.9 73.4 51.3 74.6 28.9 44.3 September 30, 2016 Total Revenues $ 4,652.2 $ 778.2 $ 597.6 $ 871.3 $ 401.7 $ 539.7 Operating Income (Loss) (1,127.9 ) (b) 204.4 131.4 171.6 98.4 147.4 Income (Loss) from Continuing Operations (764.2 ) (b) — — — — — Net Income (Loss) (764.2 ) (b) 104.1 75.4 99.9 52.8 84.4 December 31, 2016 Total Revenues $ 3,790.1 $ 729.5 $ 514.9 $ 588.2 $ 273.6 $ 402.3 Operating Income 575.9 136.2 39.6 64.3 5.5 36.4 Income from Continuing Operations 375.2 — — — — — Net Income 375.2 65.3 38.5 37.5 2.6 16.5 Quarterly Periods Ended: AEP APCo I&M OPCo PSO SWEPCo (in millions) March 31, 2015 Total Revenues $ 4,580.4 $ 899.0 $ 586.3 $ 918.4 $ 306.8 $ 431.7 Operating Income 1,102.8 273.5 124.4 122.9 34.9 92.3 Income from Continuing Operations 620.2 — — — — — Income from Discontinued Operations, Net of Tax 10.5 — — — — — Net Income 630.7 141.8 72.7 65.4 13.7 46.7 June 30, 2015 Total Revenues $ 3,826.7 $ 682.0 $ 544.3 $ 705.8 $ 319.5 $ 438.1 Operating Income 804.1 145.7 91.4 96.5 55.5 110.1 Income from Continuing Operations 431.4 — — — — — Income (Loss) from Discontinued Operations, Net of Tax (0.1 ) — — — — — Net Income 431.3 59.0 50.6 47.7 27.1 59.5 September 30, 2015 Total Revenues $ 4,431.4 $ 727.5 $ 568.3 $ 782.3 $ 420.3 $ 532.5 Operating Income 960.2 157.9 103.4 140.9 84.5 141.2 Income from Continuing Operations 511.8 — — — — — Income from Discontinued Operations, Net of Tax 7.8 — — — — — Net Income 519.6 74.6 56.6 71.6 44.7 82.1 December 31, 2015 Total Revenues $ 3,614.7 $ 655.0 $ 487.3 $ 692.2 $ 292.6 $ 378.6 Operating Income 466.4 133.7 50.7 100.5 18.3 25.6 Income from Continuing Operations 205.2 — — — — — Income from Discontinued Operations, Net of Tax 265.5 (c) — — — — — Net Income 470.7 65.2 24.9 48.0 7.0 7.7 (a) Includes final accounting adjustment for sale of AEPRO (see Note 7 ). (b) Includes impairments for Merchant Generating Assets (see Note 7 ). (c) Includes sale of AEPRO (see Note 7 ).

Goodwill and Other Intangible56

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2016
Changes in Carrying Amount of Goodwill	Corporate and Other Generation and Marketing AEP Consolidated (in millions) Balance as of December 31, 2014 $ 75.9 $ 15.4 $ 91.3 Impairment Losses — — — Goodwill Written Off Related to Sale of AEPRO (38.8 ) — (38.8 ) Balance as of December 31, 2015 37.1 15.4 52.5 Impairment Losses — — — Balance as of December 31, 2016 $ 37.1 $ 15.4 $ 52.5
Amortization Life, Gross Carrying Amount and Accumulated Amortization by Major Asset Class	December 31, 2016 2015 Amortization Life Gross Carrying Amount Accumulated Amortization Gross Carrying Amount Accumulated Amortization (in years) (in millions) Acquired Customer Contracts 5 $ 58.3 $ 58.3 $ 58.3 $ 56.5

Organization and Summary of S57

Organization and Summary of Significant Accounting Policies (Details) $ / shares in Units, $ in Millions		3 Months Ended																12 Months Ended
		Dec. 31, 2016USD ($)$ / sharesMW		Sep. 30, 2016USD ($)$ / shares		Jun. 30, 2016USD ($)$ / shares		Mar. 31, 2016USD ($)$ / shares		Dec. 31, 2015USD ($)$ / shares		Sep. 30, 2015USD ($)$ / shares		Jun. 30, 2015USD ($)$ / shares		Mar. 31, 2015USD ($)$ / shares		Dec. 31, 2016USD ($)plant$ / sharesMWshares		Dec. 31, 2015USD ($)$ / sharesshares		Dec. 31, 2014USD ($)$ / sharesshares	Dec. 31, 2013USD ($)
Assets
Current Assets		$ 6,033.9								$ 4,072.4								$ 6,033.9		$ 4,072.4
Property, Plant and Equipment, Net		45,639.3	[1]							46,133.2								45,639.3	[1]	46,133.2
Other Noncurrent Assets		11,794.5								11,477.5								11,794.5		11,477.5
TOTAL ASSETS		63,467.7								61,683.1								63,467.7		61,683.1		$ 59,544.6
Liabilities and Equity
Long-term Debt		20,256.4								19,572.7	[2]							20,256.4		19,572.7	[2]
Other Current Liabilities		1,302.8								1,305.1								1,302.8		1,305.1
Other Liabilities, Noncurrent		774.6								890.6								774.6		890.6
Equity		17,420.1								17,904.9								17,420.1		17,904.9		16,824.5	$ 16,085.6
TOTAL LIABILITIES AND EQUITY		63,467.7								61,683.1								63,467.7		61,683.1
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		$ 375.2		$ (764.2)	[3]	$ 506.4		$ 503.1		$ 205.2		$ 511.8		$ 431.4		$ 620.2		620.5		1,768.6		1,590.5
Net Income (Loss) Attributable to Noncontrolling Interests																		7.1		5.2		4.2
Income (Loss) from Continuing Operations Attributable to Parent																		$ 613.4		$ 1,763.4		$ 1,586.3
Weighted Average Number of Basic AEP Common Shares Outstanding | shares																		491,495,458		490,340,522		488,592,997
BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | $ / shares		$ 0.76	[4]	$ (1.56)	[4],[5]	$ 1.03	[4]	$ 1.02	[4]	$ 0.41	[4]	$ 1.04	[4]	$ 0.88	[4]	$ 1.27	[4]	$ 1.25		$ 3.59		$ 3.24
Weighted Average Dilutive Effect of:
Weighted Average Number of Diluted AEP Common Shares Outstanding | shares																		491,662,007		490,574,568		488,899,840
DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS FROM CONTINUING OPERATIONS | $ / shares		$ 0.76	[4]	$ (1.56)	[4],[5]	$ 1.03	[4]	$ 1.02	[4]	$ 0.41	[4]	$ 1.04	[4]	$ 0.88	[4]	$ 1.27	[4]	$ 1.25		$ 3.59		$ 3.24
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																		$ 1,688.5		$ 1,674.3		$ 1,573.7
Amortization of Certain Securitized Assets																		254.6		318.9		310.4
Amortization of Regulatory Assets and Liabilities																		19.2		16.5		13.5
Utilities Operating Expense, Depreciation and Amortization																		1,962.3		2,009.7		1,897.6
Cash Paid (Received) for:
Interest Paid, Net																		848.5		857.2		838.5
Income Taxes Paid, Net																		29.5		120.2		117.3
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																		86.1		150.2		135.1
Construction Expenditures Included in Current Liabilities as of December 31,																		858		741.4		559.3
Construction Expenditures Included in Noncurrent Liabilities as of December 31,																		0		51.6		0
Construction Expenditures Included in Noncurrent Assets as of December 31,																		0		10.5		0
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,																		2.1		37.9		44.5
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage																		0.7		2.2		3.4
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																		2,594.9		3,436.6		2,067
Repayments of Long-term Debt																		$ 1,794.9		$ 2,397.9		$ 1,777.4
Antidilutive Shares Outstanding | shares																		0		0		0
Aggregate Power Participation Ratio		43.47%																43.47%
Ohio Valley Electric Corporation [Member]
AEP Consolidated Revenues - Other Revenues:
Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned)	[6]																	$ 0.2		$ 0.1		$ 24
AEP Consolidated Expenses - Purchased Electricity for Resale:
Ohio Valley Electric Corporation (43.47% Owned)																		$ 243.7		241.7		268.5
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
AEP's Ownership in OVEC		43.47%																43.47%
AEP's Investment in OVEC		$ 4.4																$ 4.4
Supplemental Agreement During the Period Between Parties to Interconnection Agreement and OVEC																		$ 243.7		241.7		268.5
Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		25.00%
Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		59.00%
Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation																		15.00%
Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		1.00%
Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		65.00%
Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		33.00%
Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		2.00%
Appalachian Power Co [Member]
Assets
Current Assets		591.7								$ 627.9								$ 591.7		627.9
Property, Plant and Equipment, Net		9,825.8								9,424.4								9,825.8		9,424.4
Other Noncurrent Assets		1,559.7								1,596								1,559.7		1,596
TOTAL ASSETS		11,977.2								11,648.3								11,977.2		11,648.3
Liabilities and Equity
Long-term Debt		4,033.9								3,930.7								4,033.9		3,930.7
Other Current Liabilities		170.1								194								170.1		194
Other Liabilities, Noncurrent		64.5								57.7								64.5		57.7
Equity		3,583.5								3,475								3,583.5		3,475		3,366.9	3,229.4
TOTAL LIABILITIES AND EQUITY		11,977.2								11,648.3								11,977.2		11,648.3
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		$ 0		$ 0		$ 0		$ 0		0		$ 0		$ 0		$ 0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																		387.6		385.6		383.3
Amortization of Certain Securitized Assets																		0		0		0
Amortization of Regulatory Assets and Liabilities																		0.9		3.2		17.6
Utilities Operating Expense, Depreciation and Amortization																		388.5		388.8		400.9
Cash Paid (Received) for:
Interest Paid, Net																		181.8		196.7		196.7
Income Taxes Paid, Net																		22.1		30.4		15.9
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																		6.1		31.8		4.9
Construction Expenditures Included in Current Liabilities as of December 31,																		151.6		90.4		72
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																		314		726.3		394.2
Repayments of Long-term Debt																		$ 213.6		672.6		612.7
Aggregate Power Participation Ratio		43.47%																43.47%
Appalachian Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		25.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		59.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation																		15.00%
Appalachian Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		1.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		65.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		33.00%
Appalachian Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		2.00%
Indiana Michigan Power Co [Member]
Assets
Current Assets		$ 419.5								455.3								$ 419.5		455.3
Property, Plant and Equipment, Net		5,627.5								5,203.5								5,627.5		5,203.5
Other Noncurrent Assets		3,294.3								3,051.6								3,294.3		3,051.6
TOTAL ASSETS		9,341.3								8,710.4								9,341.3		8,710.4
Liabilities and Equity
Long-term Debt		2,471.4								2,000								2,471.4		2,000
Other Current Liabilities		123.4								142.1								123.4		142.1
Other Liabilities, Noncurrent		120.4								119.4								120.4		119.4
Equity		2,151.8								2,036.4								2,151.8		2,036.4		1,954	1,922.2
TOTAL LIABILITIES AND EQUITY		9,341.3								8,710.4								9,341.3		8,710.4
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		$ 0		0		0		0		0		0		0		0
AEP Consolidated Revenues - Other Revenues:
Ohio Valley Electric Corporation - Barging and Other Transportation Services (43.47% Owned)																		62.1		78.8		94.4
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																		183.9		193.5		199.3
Amortization of Certain Securitized Assets																		0		0		0
Amortization of Regulatory Assets and Liabilities																		7.8		4.9		0.9
Utilities Operating Expense, Depreciation and Amortization																		191.7		198.4		200.2
Cash Paid (Received) for:
Interest Paid, Net																		83.3		84.5		81.6
Income Taxes Paid, Net																		(39.5)		21.2		(10.2)
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																		18.2		3		16.4
Construction Expenditures Included in Current Liabilities as of December 31,																		106.2		95.8		66.1
Acquisition of Nuclear Fuel Included in Current Liabilities as of December 31,																		2.1		37.9		44.5
Expected Reimbursement For Spent Nuclear Fuel Dry Cask Storage																		0.7		2.2		3.4
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																		569.4		310.7		205.6
Repayments of Long-term Debt																		$ 100.2		332.1		218.5
Aggregate Power Participation Ratio		43.47%																43.47%
Indiana Michigan Power Co [Member] | Pension Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent		$ 25.5								21.5								$ 25.5		21.5
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		25.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		59.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation																		15.00%
Indiana Michigan Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		1.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member]
Liabilities and Equity
Other Liabilities, Noncurrent		0								0								$ 0		0
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		65.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		33.00%
Indiana Michigan Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		2.00%
Ohio Power Co [Member]
Assets
Current Assets		270.9								573.2								$ 270.9		573.2
Property, Plant and Equipment, Net		5,325.6								5,054.7								5,325.6		5,054.7
Other Noncurrent Assets		1,497.4								1,510								1,497.4		1,510
TOTAL ASSETS		7,093.9								7,137.9								7,093.9		7,137.9
Liabilities and Equity
Long-term Debt		1,763.9								2,157.7								1,763.9		2,157.7
Other Current Liabilities		236								154.3								236		154.3
Other Liabilities, Noncurrent		83.9								30.7								83.9		30.7
Equity		2,117.5								1,986.6								2,117.5		1,986.6		1,980.2	1,625.3
TOTAL LIABILITIES AND EQUITY		7,093.9								7,137.9								7,093.9		7,137.9
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		0		0		0		0		0		0		0		0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																		202.3		184.4		188.3
Amortization of Certain Securitized Assets																		44.3		43.3		43.5
Amortization of Regulatory Assets and Liabilities																		(8)		(10.2)		(18.1)
Utilities Operating Expense, Depreciation and Amortization																		238.6		217.5		213.7
Cash Paid (Received) for:
Interest Paid, Net																		109.9		121.6		132.4
Income Taxes Paid, Net																		220.4		26.1		44
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																		3.4		2.7		4.8
Construction Expenditures Included in Current Liabilities as of December 31,																		44.6		34.3		43.4
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Notes Receivable - Affiliated		$ 32.3								32.3								32.3		32.3
Repayments of Long-term Debt																		$ 395.9		131.5		438.6
Aggregate Power Participation Ratio		43.47%																43.47%
Ohio Power Co [Member] | Ohio Valley Electric Corporation [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
AEP's Ownership in OVEC		4.30%																4.30%
AEP's Investment in OVEC		$ 0.4																$ 0.4
Ohio Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		25.00%
Ohio Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		59.00%
Ohio Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation																		15.00%
Ohio Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		1.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		65.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		33.00%
Ohio Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		2.00%
Public Service Co Of Oklahoma [Member]
Assets
Current Assets		195.4								245.4								$ 195.4		245.4
Property, Plant and Equipment, Net		3,823.2								3,693.2								3,823.2		3,693.2
Other Noncurrent Assets		360.6								231.8								360.6		231.8
TOTAL ASSETS		4,379.2								4,170.4								4,379.2		4,170.4
Liabilities and Equity
Long-term Debt		1,286								1,286.1								1,286		1,286.1
Other Current Liabilities		47.8								64.4								47.8		64.4
Other Liabilities, Noncurrent		11.2								13.7								11.2		13.7
Equity		1,214.1								1,119.9								1,214.1		1,119.9		1,028.2	942.1
TOTAL LIABILITIES AND EQUITY		4,379.2								4,170.4								4,379.2		4,170.4
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		0		0		0		0		0		0		0		0
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																		122.6		108.6		99.7
Amortization of Certain Securitized Assets																		0		0		0
Amortization of Regulatory Assets and Liabilities																		7.6		8.9		1.3
Utilities Operating Expense, Depreciation and Amortization																		130.2		117.5		101
Cash Paid (Received) for:
Interest Paid, Net																		60.1		54.8		52.8
Income Taxes Paid, Net																		(37.7)		7.9		(21.2)
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																		3.1		3.6		2.3
Construction Expenditures Included in Current Liabilities as of December 31,																		33.6		47.4		38.6
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																		274.2		248.8		75
Repayments of Long-term Debt																		$ 275.4		0.4		34.1
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		25.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		59.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation																		15.00%
Public Service Co Of Oklahoma [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		1.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		65.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		33.00%
Public Service Co Of Oklahoma [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		2.00%
Southwestern Electric Power Co [Member]
Assets
Current Assets		546								335.3								$ 546		335.3
Property, Plant and Equipment, Net		6,429.5								6,321.1								6,429.5		6,321.1
Other Noncurrent Assets		651.1								491.6								651.1		491.6
TOTAL ASSETS		7,626.6								7,148								7,626.6		7,148
Liabilities and Equity
Long-term Debt		2,679.1								2,273.5								2,679.1		2,273.5
Other Current Liabilities		83.9								110.7								83.9		110.7
Other Liabilities, Noncurrent		9.7								49.3								9.7		49.3
Equity		2,215.2								2,169.7								2,215.2		2,169.7		2,097.2	$ 2,055.9
TOTAL LIABILITIES AND EQUITY		7,626.6								7,148								7,626.6		7,148
Amounts Attributable to AEP Common Shareholders
Income (Loss) from Continuing Operations, Including Portion Attributable to Noncontrolling Interest		$ 0		$ 0		$ 0		$ 0		$ 0		$ 0		$ 0		$ 0
Net Income (Loss) Attributable to Noncontrolling Interests																		4.1		3.7		4.2
Supplemental Income Statement Elements [Abstract]
Depreciation and Amortization of Property, Plant and Equipment																		196.6		190.7		183.2
Amortization of Certain Securitized Assets																		0		0		0
Amortization of Regulatory Assets and Liabilities																		(0.1)		1.3		1.9
Utilities Operating Expense, Depreciation and Amortization																		196.5		192		185.1
Cash Paid (Received) for:
Interest Paid, Net																		118		112.6		116.9
Income Taxes Paid, Net																		(32)		15.4		(152.2)
Noncash Investing and Financing Activities:
Capital Lease Obligations Incurred																		5.9		7.4		4.1
Construction Expenditures Included in Current Liabilities as of December 31,																		41.8		92.9		94.3
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Issuance of Long-term Debt																		406.7		445.9		99.4
Repayments of Long-term Debt																		$ 3.3		$ 306.8		$ 3.3
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		25.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		59.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Other Investments [Member]
Target Asset Allocations
Target Asset Allocation																		15.00%
Southwestern Electric Power Co [Member] | Pension Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		1.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Equity [Member]
Target Asset Allocations
Target Asset Allocation																		65.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Fixed Income [Member]
Target Asset Allocations
Target Asset Allocation																		33.00%
Southwestern Electric Power Co [Member] | Other Postretirement Benefit Plans [Member] | Cash and Cash Equivalents [Member]
Target Asset Allocations
Target Asset Allocation																		2.00%
Ohio Valley Electric Corporation [Member]
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]
Approximate OVEC Generating Capacity (In MWs) | MW		2,400																2,400
Number of OVEC Generating Plants | plant																		2
Outstanding Indebtedness																		$ 1,500
Restricted Stock Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares | shares																		200,000		300,000		300,000
Dilutive Securities, Effect on Basic Earnings Per Share | $ / shares																		$ 0		$ 0		$ 0
[1]	Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
[2]	.
[3]	Includes impairments for Merchant Generating Assets (see Note 7).
[4]	Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
[5]	Relates to impairments for Merchant Generating Assets (see Note 7).
[6]	AEP did not ship coal to OVEC in 2016 and 2015.

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		$ (127.1)	$ (103.1)	$ (115.2)
Change in Fair Value Recognized in AOCI		(28)	(20.7)	(7.8)
Commodity
Vertically Integrated Utilities Revenues		9,012.4	9,069.9	9,396.8
Generation & Marketing Revenues		180.7	124.6	44.9
Purchased Electricity for Resale		2,821.4	2,760.1	2,085.9
Other Operation Expense		2,956.9	2,703.9	2,766.6
Maintenance Expense		1,237.7	1,325.3	1,328
Interest Rate
Depreciation and Amortization Expense		1,962.3	2,009.7	1,897.6
Interest Expense		877.2	873.9	868
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(1.7)	(14.3)	30.7
Income Tax Expense (Benefit)		73.7	(919.6)	(902.6)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(1.2)	(9.3)	19.9
Other Comprehensive Income (Loss), Net of Tax		(29.2)	(30)	12.1
Pension and OPEB Adjustment Related to Mitchell Plant			6
Ending Balance in AOCI		(156.3)	(127.1)	(103.1)
Securities Available for Sale [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		7.1	7.7	6.8
Change in Fair Value Recognized in AOCI		1.3	(0.6)	0.9
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	0
Other Comprehensive Income (Loss), Net of Tax		1.3	(0.6)	0.9
Pension and OPEB Adjustment Related to Mitchell Plant			0
Ending Balance in AOCI		8.4	7.1	7.7
Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		139.9	138.7	133.9
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0.9	1.8	7.4
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0.6	1.2	4.8
Other Comprehensive Income (Loss), Net of Tax		0.6	1.2	4.8
Pension and OPEB Adjustment Related to Mitchell Plant			0
Ending Balance in AOCI		140.5	139.9	138.7
Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(251.7)	(232)	(233.1)
Change in Fair Value Recognized in AOCI		(14.7)	(25.7)	1.1
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	0
Other Comprehensive Income (Loss), Net of Tax		(14.7)	(25.7)	1.1
Pension and OPEB Adjustment Related to Mitchell Plant			6
Ending Balance in AOCI		(266.4)	(251.7)	(232)
Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Other Comprehensive Income (Loss), Net of Tax		(29.2)	(30)	12.1
Pension and OPEB Adjustment Related to Mitchell Plant			6
Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(5.2)	1.6	0.2
Change in Fair Value Recognized in AOCI		(14.6)	5.6	(9.8)
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(5)	(19)	17.2
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(3.3)	(12.4)	11.2
Other Comprehensive Income (Loss), Net of Tax		(17.9)	(6.8)	1.4
Pension and OPEB Adjustment Related to Mitchell Plant			0
Ending Balance in AOCI		(23.1)	(5.2)	1.6
Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(17.2)	(19.1)	(23)
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		2.4	2.9	6.1
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		1.5	1.9	3.9
Other Comprehensive Income (Loss), Net of Tax		1.5	1.9	3.9
Pension and OPEB Adjustment Related to Mitchell Plant			0
Ending Balance in AOCI		(15.7)	(17.2)	(19.1)
Reclassifications from Accumulated Other Comprehensive Income [Member]
Commodity
Generation & Marketing Revenues		(21.4)	(48.1)	59.1
Purchased Electricity for Resale		16.4	29.1	(39.1)
Regulatory Assets/(Liabilities), Net	[1]			(2.8)
Interest Rate
Interest Expense		2.4	2.9	6.1
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(19.4)	(19.5)	(20.6)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		20.3	21.3	28
Income Tax Expense (Benefit)		(0.5)	(5)	10.8
Reclassifications from Accumulated Other Comprehensive Income [Member] | Securities Available for Sale [Member]
Commodity
Generation & Marketing Revenues		0	0	0
Purchased Electricity for Resale		0	0	0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Generation & Marketing Revenues		0	0	0
Purchased Electricity for Resale		0	0	0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(19.4)	(19.5)	(20.6)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		20.3	21.3	28
Income Tax Expense (Benefit)		0.3	0.6	2.6
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Generation & Marketing Revenues		0	0	0
Purchased Electricity for Resale		0	0	0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0	0	0
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Generation & Marketing Revenues		(21.4)	(48.1)	59.1
Purchased Electricity for Resale		16.4	29.1	(39.1)
Regulatory Assets/(Liabilities), Net	[1]			(2.8)
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		(1.7)	(6.6)	6
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Generation & Marketing Revenues		0	0	0
Purchased Electricity for Resale		0	0	0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		2.4	2.9	6.1
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0.9	1	2.2
Appalachian Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(2.8)	5	2.9
Change in Fair Value Recognized in AOCI		(3.5)	(5.7)	4.4
Commodity
Vertically Integrated Utilities Revenues		2,847.4	2,805.6	2,899.4
Generation & Marketing Revenues		11.7	10.1	9.2
Purchased Electricity for Resale		329.3	395.2	456.6
Other Operation Expense		486.7	405.4	427.7
Maintenance Expense		275	263.3	259.3
Interest Rate
Depreciation and Amortization Expense		388.5	388.8	400.9
Interest Expense		188.5	192.3	209.6
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(3.2)	(3.2)	(3.5)
Income Tax Expense (Benefit)		(199.1)	(194.3)	(154.9)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(2.1)	(2.1)	(2.3)
Other Comprehensive Income (Loss), Net of Tax		(5.6)	(7.8)	2.1
Ending Balance in AOCI		(8.4)	(2.8)	5
Appalachian Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		17.4	19.2	20.5
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(2.1)	(2.8)	(2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(1.4)	(1.8)	(1.3)
Other Comprehensive Income (Loss), Net of Tax		(1.4)	(1.8)	(1.3)
Ending Balance in AOCI		16	17.4	19.2
Appalachian Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(23.8)	(18.1)	(20.8)
Change in Fair Value Recognized in AOCI		(3.5)	(5.7)	2.7
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	0
Other Comprehensive Income (Loss), Net of Tax		(3.5)	(5.7)	2.7
Ending Balance in AOCI		(27.3)	(23.8)	(18.1)
Appalachian Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Other Comprehensive Income (Loss), Net of Tax		(5.6)	(7.8)	2.1
Appalachian Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	0	0.1
Change in Fair Value Recognized in AOCI		0	0	1.7
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	(2.7)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	(1.8)
Other Comprehensive Income (Loss), Net of Tax		0	0	(0.1)
Ending Balance in AOCI		0	0	0
Appalachian Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		3.6	3.9	3.1
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(1.1)	(0.4)	1.2
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(0.7)	(0.3)	0.8
Other Comprehensive Income (Loss), Net of Tax		(0.7)	(0.3)	0.8
Ending Balance in AOCI		2.9	3.6	3.9
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Commodity
Purchased Electricity for Resale				(0.5)
Regulatory Assets/(Liabilities), Net	[1]			(2.2)
Interest Rate
Interest Expense		(1.1)	(0.4)	1.2
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(5.1)	(5.1)	(5.1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		3	2.3	3.1
Income Tax Expense (Benefit)		(1.1)	(1.1)	(1.2)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Purchased Electricity for Resale				0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(5.1)	(5.1)	(5.1)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		3	2.3	3.1
Income Tax Expense (Benefit)		(0.7)	(1)	(0.7)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Purchased Electricity for Resale				0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0	0	0
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale				(0.5)
Regulatory Assets/(Liabilities), Net	[1]			(2.2)
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0	0	(0.9)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale				0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		(1.1)	(0.4)	1.2
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		(0.4)	(0.1)	0.4
Indiana Michigan Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(16.7)	(14.3)	(15.5)
Change in Fair Value Recognized in AOCI		(0.8)	(3.5)	0.6
Commodity
Vertically Integrated Utilities Revenues		2,062.3	2,073.3	2,149.1
Generation & Marketing Revenues		17	6.7	2
Purchased Electricity for Resale		198.7	195.8	96.8
Other Operation Expense		572	553.4	586
Maintenance Expense		205.6	212	228.5
Interest Rate
Depreciation and Amortization Expense		191.7	198.4	200.2
Interest Expense		100.8	90.2	93.5
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		2	1.7	0.9
Income Tax Expense (Benefit)		(67.5)	(96.1)	(79.6)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		1.3	1.1	0.6
Other Comprehensive Income (Loss), Net of Tax		0.5	(2.4)	1.2
Ending Balance in AOCI		(16.2)	(16.7)	(14.3)
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		5.1	5.1	4.9
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	0.3
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	0.2
Other Comprehensive Income (Loss), Net of Tax		0	0	0.2
Ending Balance in AOCI		5.1	5.1	5.1
Indiana Michigan Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(8.5)	(5)	(4.5)
Change in Fair Value Recognized in AOCI		(0.8)	(3.5)	(0.5)
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	0
Other Comprehensive Income (Loss), Net of Tax		(0.8)	(3.5)	(0.5)
Ending Balance in AOCI		(9.3)	(8.5)	(5)
Indiana Michigan Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Other Comprehensive Income (Loss), Net of Tax		0.5	(2.4)	1.2
Indiana Michigan Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	0	0.1
Change in Fair Value Recognized in AOCI		0	0	1.1
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	(1.8)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	(1.2)
Other Comprehensive Income (Loss), Net of Tax		0	0	(0.1)
Ending Balance in AOCI		0	0	0
Indiana Michigan Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(13.3)	(14.4)	(16)
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		2	1.7	2.4
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		1.3	1.1	1.6
Other Comprehensive Income (Loss), Net of Tax		1.3	1.1	1.6
Ending Balance in AOCI		(12)	(13.3)	(14.4)
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Commodity
Purchased Electricity for Resale				(0.8)
Regulatory Assets/(Liabilities), Net	[1]			(1)
Interest Rate
Interest Expense		2	1.7	2.4
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(0.8)	(0.9)	(0.8)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0.8	0.9	1.1
Income Tax Expense (Benefit)		0.7	0.6	0.3
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Purchased Electricity for Resale				0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(0.8)	(0.9)	(0.8)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0.8	0.9	1.1
Income Tax Expense (Benefit)		0	0	0.1
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Purchased Electricity for Resale				0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0	0	0
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale				(0.8)
Regulatory Assets/(Liabilities), Net	[1]			(1)
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0	0	(0.6)
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Purchased Electricity for Resale				0
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		2	1.7	2.4
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0.7	0.6	0.8
Ohio Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		4.3	5.6	7.1
Change in Fair Value Recognized in AOCI		0	0	0
Commodity
Generation & Marketing Revenues		6.5	8.5	6.8
Purchased Electricity for Resale		663.1	635	282
Other Operation Expense		706.8	630.3	594.8
Maintenance Expense		148	166.8	196
Interest Rate
Depreciation and Amortization Expense		238.6	217.5	213.7
Interest Expense		112.2	127.8	128.3
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(1.9)	(2)	(2.3)
Income Tax Expense (Benefit)		(143.8)	(126.5)	(132.2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(1.3)	(1.3)	(1.5)
Other Comprehensive Income (Loss), Net of Tax		(1.3)	(1.3)	(1.5)
Ending Balance in AOCI		3	4.3	5.6
Ohio Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		58.4	58.4	58.4
Change in Fair Value Recognized in AOCI			0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			0	0
Other Comprehensive Income (Loss), Net of Tax			0	0
Ending Balance in AOCI			58.4	58.4
Ohio Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(58.4)	(58.4)	(58.4)
Change in Fair Value Recognized in AOCI			0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax			0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax			0	0
Other Comprehensive Income (Loss), Net of Tax			0	0
Ending Balance in AOCI			(58.4)	(58.4)
Ohio Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Other Comprehensive Income (Loss), Net of Tax		(1.3)	(1.3)	(1.5)
Ohio Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	0	0.1
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	(0.2)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	(0.1)
Other Comprehensive Income (Loss), Net of Tax		0	0	(0.1)
Ending Balance in AOCI		0	0	0
Ohio Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		4.3	5.6	7
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(1.9)	(2)	(2.1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(1.3)	(1.3)	(1.4)
Other Comprehensive Income (Loss), Net of Tax		(1.3)	(1.3)	(1.4)
Ending Balance in AOCI		3	4.3	5.6
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			(0.2)
Interest Rate
Interest Expense		(1.9)	(2)	(2.1)
Pension and OPEB
Income Tax Expense (Benefit)		(0.6)	(0.7)	(0.8)
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense			0	0
Pension and OPEB
Income Tax Expense (Benefit)			0	0
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense			0	0
Pension and OPEB
Income Tax Expense (Benefit)			0	0
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			(0.2)
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Income Tax Expense (Benefit)		0	0	(0.1)
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		(1.9)	(2)	(2.1)
Pension and OPEB
Income Tax Expense (Benefit)		(0.6)	(0.7)	(0.7)
Public Service Co Of Oklahoma [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		4.2	5	5.8
Change in Fair Value Recognized in AOCI		0	0	0
Commodity
Vertically Integrated Utilities Revenues		1,242.8	1,331.4	1,340.3
Generation & Marketing Revenues		4.4	3.2	4.2
Purchased Electricity for Resale		441.2	316.9	385
Other Operation Expense		288.5	268.4	262.8
Maintenance Expense		106.9	104.6	108
Interest Rate
Depreciation and Amortization Expense		130.2	117.5	101
Interest Expense		51.2	58.6	54.6
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(1.2)	(1.2)	(1.2)
Income Tax Expense (Benefit)		(54.4)	(51.3)	(50.6)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(0.8)	(0.8)	(0.8)
Other Comprehensive Income (Loss), Net of Tax		(0.8)	(0.8)	(0.8)
Ending Balance in AOCI		3.4	4.2	5
Public Service Co Of Oklahoma [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Other Comprehensive Income (Loss), Net of Tax		(0.8)	(0.8)	(0.8)
Public Service Co Of Oklahoma [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	0	0.1
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	(0.1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	(0.1)
Other Comprehensive Income (Loss), Net of Tax		0	0	(0.1)
Ending Balance in AOCI		0	0	0
Public Service Co Of Oklahoma [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		4.2	5	5.7
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(1.2)	(1.2)	(1.1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(0.8)	(0.8)	(0.7)
Other Comprehensive Income (Loss), Net of Tax		(0.8)	(0.8)	(0.7)
Ending Balance in AOCI		3.4	4.2	5
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			(0.1)
Interest Rate
Interest Expense		(1.2)	(1.2)	(1.1)
Pension and OPEB
Income Tax Expense (Benefit)		(0.4)	(0.4)	(0.4)
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			(0.1)
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Income Tax Expense (Benefit)		0	0	0
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		(1.2)	(1.2)	(1.1)
Pension and OPEB
Income Tax Expense (Benefit)		(0.4)	(0.4)	(0.4)
Southwestern Electric Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(9.4)	(7.5)	(8.5)
Change in Fair Value Recognized in AOCI		(1)	(2.9)	(0.3)
Commodity
Vertically Integrated Utilities Revenues		1,721.5	1,762.3	1,817.9
Generation & Marketing Revenues		2	2	2.2
Purchased Electricity for Resale		142.4	110.6	178.1
Other Operation Expense		331.7	294.5	272.8
Maintenance Expense		149.7	155.9	149.2
Interest Rate
Depreciation and Amortization Expense		196.5	192	185.1
Interest Expense		119.7	119.9	126.1
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		1.6	1.6	2
Income Tax Expense (Benefit)		(52.1)	(84.8)	(66.4)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		1	1	1.3
Other Comprehensive Income (Loss), Net of Tax		0	(1.9)	1
Ending Balance in AOCI		(9.4)	(9.4)	(7.5)
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		2.6	3.6	4.5
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		(1.1)	(1.5)	(1.4)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(0.7)	(1)	(0.9)
Other Comprehensive Income (Loss), Net of Tax		(0.7)	(1)	(0.9)
Ending Balance in AOCI		1.9	2.6	3.6
Southwestern Electric Power Co [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(2.9)	0	0.3
Change in Fair Value Recognized in AOCI		(1)	(2.9)	(0.3)
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	0
Other Comprehensive Income (Loss), Net of Tax		(1)	(2.9)	(0.3)
Ending Balance in AOCI		(3.9)	(2.9)	0
Southwestern Electric Power Co [Member] | Accumulated Other Comprehensive Income [Member]
Pension and OPEB
Other Comprehensive Income (Loss), Net of Tax			(1.9)	1
Southwestern Electric Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	0	0
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		0	0	(0.1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0	0	0
Other Comprehensive Income (Loss), Net of Tax		0	0	0
Ending Balance in AOCI		0	0	0
Southwestern Electric Power Co [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(9.1)	(11.1)	(13.3)
Change in Fair Value Recognized in AOCI		0	0	0
Pension and OPEB
Reclassification from Accumulated Other Comprehensive Income, Current Period, before Tax		2.7	3.1	3.5
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		1.7	2	2.2
Other Comprehensive Income (Loss), Net of Tax		1.7	2	2.2
Ending Balance in AOCI		(7.4)	(9.1)	(11.1)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			(0.1)
Interest Rate
Interest Expense		2.7	3.1	3.5
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(1.8)	(1.9)	(1.9)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0.7	0.4	0.5
Income Tax Expense (Benefit)		0.6	0.6	0.7
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Amortization of Deferred Costs [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		(1.8)	(1.9)	(1.9)
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0.7	0.4	0.5
Income Tax Expense (Benefit)		(0.4)	(0.5)	(0.5)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member] | Changes in Funded Status [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0	0	0
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			(0.1)
Interest Rate
Interest Expense		0	0	0
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		0	0	(0.1)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate [Member] | Cash Flow Hedges [Member]
Commodity
Regulatory Assets/(Liabilities), Net	[1]			0
Interest Rate
Interest Expense		2.7	3.1	3.5
Pension and OPEB
Other Comprehensive (Income) Loss, Amortization Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Prior Service Cost (Credit), before Tax		0	0	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI, Pension and Other Postretirement Benefit Plans, for Net Gain (Loss), before Tax		0	0	0
Income Tax Expense (Benefit)		$ 1	$ 1.1	$ 1.3
[1]	(a)Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Rate Matters - East Companies

Rate Matters - East Companies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)$ / MWD$ / MWhMW	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Public Utilities, General Disclosures [Line Items]
Fuel and Other Consumables Used for Electric Generation	$ 2,908.9	$ 3,348.1	$ 4,271.8
Purchased Electricity for Resale	2,821.4	2,760.1	2,085.9
Other Operation	2,956.9	2,703.9	2,766.6
Depreciation and Amortization	1,962.3	2,009.7	1,897.6
Noncurrent Regulatory Assets	5,625.5	5,140.3
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Fuel and Other Consumables Used for Electric Generation	654.9	675.9	813.4
Purchased Electricity for Resale	329.3	395.2	456.6
Other Operation	486.7	405.4	427.7
Depreciation and Amortization	388.5	388.8	400.9
Noncurrent Regulatory Assets	1,121.1	1,154.2
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Fuel and Other Consumables Used for Electric Generation	284.1	336.3	476.6
Purchased Electricity for Resale	198.7	195.8	96.8
Other Operation	572	553.4	586
Depreciation and Amortization	191.7	198.4	200.2
Noncurrent Regulatory Assets	916.6	804.3
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Purchased Electricity for Resale	663.1	635	282
Other Operation	706.8	630.3	594.8
Depreciation and Amortization	238.6	217.5	$ 213.7
Noncurrent Regulatory Assets	$ 1,107.5	$ 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%
Approved Recovery Percentage of Certain Transmission Expense through the Indiana PJM Rider from January 2017 Through June 2018	100.00%
Approved Cap on Amounts Recovered Through the Indiana PJM Rider from January 2017 Through June 2018	$ 109
Approved 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%
Approved Recovery Percentage of Certain Transmission Expense through the Indiana PJM Rider from January 2017 Through June 2018	100.00%
Approved Cap on Amounts Recovered Through the Indiana PJM Rider from January 2017 Through June 2018	$ 109
Approved Recovery Percentage of Certain Transmission Expense Through the Indiana PJM Rider from July 2018 Until IURC Addresses in Subsequent Proceeding	100.00%
Kingsport Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Approved Base Rate Increase	$ 8
Approved Return on Common Equity	9.85%
Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
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
Approved Return on Common Equity	10.20%
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 (in MWs) | MW	400
Wind Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW	500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement	100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement	50.00%
Temporary Customer-Specific Rate Impact Cap Through May 2018	5.00%
PUCO Approved Reduced Customer Credits	$ 15
Return on Common Equity Proposed in the Amended ESP Filing	10.41%
Future Commitment to Support the Development of a 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]
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
Approved Return on Common Equity	10.20%
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 (in MWs) | MW	400
Wind Energy Projects to be Developed and Implemented by 2021 as Proposed in Stipulation Agreement (in MWs) | MW	500
Percentage of Output to be Received from Solar and Wind Projects as Proposed in Stipulation Agreement	100.00%
Maximum Ownership Percentage of Solar and Wind Projects as Proposed in Stipulation Agreement	50.00%
Temporary Customer-Specific Rate Impact Cap Through May 2018	5.00%
PUCO Approved Reduced Customer Credits	$ 15
Return on Common Equity Proposed in the Amended ESP Filing	10.41%
Future Commitment to Support the Development of a 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
Ohio Global Settlement [Member]
Public Utilities, General Disclosures [Line Items]
Proposed Reduction in PIRR Rate Collected from Customers	97
Proposed Total RSR Revenues to be Collected Through June 2019	$ 388
Proposed RSR Collection Period (in months)	30 months
Increase in RSR Capacity Costs Recorded in December 2016 Resulting from Global Settlement	$ 83
Increase in RSR Capacity Costs Related Carrying Charges Recorded in December 2016 Resulting from Global Settlement	14
Fuel and Other Consumables Used for Electric Generation	(19)
Purchased Electricity for Resale	(19.9)
Other Operation	(15.7)
Depreciation and Amortization	(42.1)
Total Decrease in RSR Expense Recorded in December 2016 Resulting from Global Settlement	(96.7)
Proposed Refund to Customers Associated with Remands Related to SEET	$ 20
Proposed Refund Period (in months)	12 months
Amount Accrued in December 2016 Related to Proposed Customer Refunds	$ 20
Proposed Refund to SSO Customers Related to OVEC and Lawrenceburg Purchases	100
Amount Accrued in December 2016 Related to Proposed SSO Customer Refunds	100
Ohio Global Settlement [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Proposed Reduction in PIRR Rate Collected from Customers	97
Proposed Total RSR Revenues to be Collected Through June 2019	$ 388
Proposed RSR Collection Period (in months)	30 months
Increase in RSR Capacity Costs Recorded in December 2016 Resulting from Global Settlement	$ 83
Increase in RSR Capacity Costs Related Carrying Charges Recorded in December 2016 Resulting from Global Settlement	14
Proposed Refund to Customers Associated with Remands Related to SEET	$ 20
Proposed Refund Period (in months)	12 months
Amount Accrued in December 2016 Related to Proposed Customer Refunds	$ 20
Proposed Refund to SSO Customers Related to OVEC and Lawrenceburg Purchases	100
Amount Accrued in December 2016 Related to Proposed SSO Customer Refunds	100
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]
Noncurrent Regulatory Assets	$ 202
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months)	32 months
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]
Noncurrent Regulatory Assets	$ 202
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months)	32 months
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 Global Settlement [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets	299
Deferred Capacity Costs [Member] | Ohio Global Settlement [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Noncurrent Regulatory Assets	$ 299

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Thousands	1 Months Ended	12 Months Ended
	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 3,183,900	$ 3,903,900
Remaining Contractual Construction Obligations		7,038,600
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		148,200	315,300
Remaining Contractual Construction Obligations		898,600
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		113,800	$ 751,300
Remaining Contractual Construction Obligations		668,000
Welsh Plant, Unit 2 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified As Regulatory Assets Upon Retirement Of Plant		76,000
Welsh Plant, Unit 2 [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified As Regulatory Assets Upon Retirement Of Plant		76,000
2012 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances		114,000
Resulting Approved Base Rate Increase		52,000
2012 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances		114,000
Resulting Approved Base Rate Increase		52,000
2016 Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Amount Of Increase Related To Environmental Controls		$ 34,000
Requested Return on Common Equity		10.00%
Requested Net Increase in Texas Annual Revenues		$ 69,000
Amount of Increase Related to Additonal Investment and Increased Operating Costs		25,000
Amount of Increase Related to Transmission Cost Recovery		8,000
Amount of Increase Related to Vegetation Management		2,000
2016 Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount Of Increase Related To Environmental Controls		$ 34,000
Requested Return on Common Equity		10.00%
Requested Net Increase in Texas Annual Revenues		$ 69,000
Amount of Increase Related to Additonal Investment and Increased Operating Costs		25,000
Amount of Increase Related to Transmission Cost Recovery		8,000
Amount of Increase Related to Vegetation Management		2,000
AEP Texas Distribution Cost Recovery Factor [Member]
Public Utilities, General Disclosures [Line Items]
Annual Revenue Requirement Approved in Settlement Agreement		$ 56,000
ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Parent Equity Ownership Interest in ETT		50.00%
AEP Share of ETT Cumulative Revenues Subject to Review		$ 591,000
Louisiana 2012 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		29.00%
Net Increase in Louisiana Total Rates per the Settlement Agreement		$ 2,000
Base Rate Increase per the Settlement Agreement		85,000
Fuel Rate Decrease per the Settlement Agreement		$ 83,000
Return on Common Equity per the Settlement Agreement		10.00%
Reduction to Requested Revenue Increase as Approved in Stipulation Agreement		$ 3,000
Louisiana 2012 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		29.00%
Net Increase in Louisiana Total Rates per the Settlement Agreement		$ 2,000
Base Rate Increase per the Settlement Agreement		85,000
Fuel Rate Decrease per the Settlement Agreement		$ 83,000
Return on Common Equity per the Settlement Agreement		10.00%
Reduction to Requested Revenue Increase as Approved in Stipulation Agreement		$ 3,000
Louisiana 2014 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		5,000
Additional Requested Annual Increase		15,000
Requested Total Annual Increase		20,000
Amount Of Interim Rates Implemented In January 2015 As Approved In Partial Settlement Agreement		15,000
Louisiana 2014 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		5,000
Additional Requested Annual Increase		15,000
Requested Total Annual Increase		20,000
Amount Of Interim Rates Implemented In January 2015 As Approved In Partial Settlement Agreement		15,000
Louisiana 2015 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		14,000
Louisiana 2015 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		14,000
Oklahoma 2015 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		137,000
Requested Base Rate Increase		89,000
Amount Of Increased Depreciation Expense Requested		48,000
Amount Of Increase Related To Environmental Controls		44,000
Amount Of Requested Increase Related To Environmental Consumable Costs In Fuel Adjustment Clause		$ 4,000
Requested Return on Common Equity		10.50%
Interim Annual Base Rate Increase		$ 75,000
Future Incremental Purchased Capacity And Energy Costs Related To Environmental Projects		35,000
Approved Net Annual Revenue Increase		$ 19,000
Approved Return on Common Equity		9.50%
Oklahoma 2015 Base Rate Case [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		$ 137,000
Requested Base Rate Increase		89,000
Amount Of Increased Depreciation Expense Requested		48,000
Amount Of Increase Related To Environmental Controls		44,000
Amount Of Requested Increase Related To Environmental Consumable Costs In Fuel Adjustment Clause		$ 4,000
Requested Return on Common Equity		10.50%
Interim Annual Base Rate Increase		$ 75,000
Future Incremental Purchased Capacity And Energy Costs Related To Environmental Projects		35,000
Approved Net Annual Revenue Increase		$ 19,000
Approved Return on Common Equity		9.50%
Oklahoma 2015 Base Rate Case [Member] | Northeastern Plant, Unit 3 And Comanche Plant [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		$ 219,000
Oklahoma 2015 Base Rate Case [Member] | Northeastern Plant, Unit 3 And Comanche Plant [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		219,000
Oklahoma 2015 Base Rate Case [Member] | Northeastern Plant, Unit 4 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified As Regulatory Assets Upon Retirement Of Plant		87,000
Oklahoma 2015 Base Rate Case [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 Plant		87,000
SPP Open Access Transmission Tariff Upgrade Costs [Member]
Public Utilities, General Disclosures [Line Items]
Net Unfavorable Impact		7,000
SPP Open Access Transmission Tariff Upgrade Costs [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Net Unfavorable Impact		3,000
SPP Open Access Transmission Tariff Upgrade Costs [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Net Unfavorable Impact		4,000
TCC and TNC Merger [Member]
Public Utilities, General Disclosures [Line Items]
Annual Credit to Customers Related to Debt Issuance Savings Resulting from Merger		630
TCC Distribution Cost Recovery Factor [Member]
Public Utilities, General Disclosures [Line Items]
Annual Revenue Requirement Approved in Settlement Agreement		45,000
TNC Distribution Cost Recovery Factor [Member]
Public Utilities, General Disclosures [Line Items]
Annual Revenue Requirement Approved in Settlement Agreement		11,000
Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		850,000
Construction Work in Progress		397,000
Remaining Contractual Construction Obligations		11,000
Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		69,000
Amount of Additional Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		10,000
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		79,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals		8,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity		5,000
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		850,000
Construction Work in Progress		397,000
Remaining Contractual Construction Obligations		11,000
Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		69,000
Amount of Additional Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		10,000
Total Amount of Recovery Requested Related to Arkansas Retail Jurisdictional Share of Environmental Costs		79,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferrals		8,000
Amount of LPSC Approved Eligible Welsh Plant Environmental Control Deferred Unrecognized Equity		5,000
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		$ 633,000
Texas Jurisdictional Share of the Welsh Plant		33.00%
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		$ 633,000
Texas Jurisdictional Share of the Welsh Plant		33.00%
Subsequent Event [Member] | ETT Interim Transmission Rates [Member]
Public Utilities, General Disclosures [Line Items]
Annual Revenue Requirement Decrease Approved by the PUCT	$ 46,000
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		$ 370,000
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		370,000
Environmental Controls Projects [Member] | Oklahoma 2015 Base Rate Case [Member] | Comanche Plant [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		44,000
Environmental Controls Projects [Member] | Oklahoma 2015 Base Rate Case [Member] | Comanche Plant [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		44,000
Environmental Controls Projects [Member] | Oklahoma 2015 Base Rate Case [Member] | Northeastern Plant, Unit 3 [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		181,000
Environmental Controls Projects [Member] | Oklahoma 2015 Base Rate Case [Member] | Northeastern Plant, Unit 3 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 181,000

Effects of Regulation (Details)

Effects of Regulation (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015
Regulatory Assets
Current Regulatory Assets		$ 156.6	$ 115.2
Noncurrent Regulatory Assets		5,625.5	5,140.3
Accumulated Depreciation and Amortization		16,397.3	19,348.2
Regulatory Liabilities
Current Regulatory Liabilities		8	113.9
Noncurrent Regulatory Liabilities		3,751.3	3,736.1
Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		68.4	86.9
Noncurrent Regulatory Assets		1,121.1	1,154.2
Accumulated Depreciation and Amortization		3,636.8	3,407.6
Regulatory Liabilities
Noncurrent Regulatory Liabilities		627.8	637.1
Indiana Michigan Power Co [Member]
Regulatory Assets
Current Regulatory Assets		26.1	11.6
Noncurrent Regulatory Assets		916.6	804.3
Accumulated Depreciation and Amortization		3,005.1	3,018
Regulatory Liabilities
Current Regulatory Liabilities		0	0.3
Noncurrent Regulatory Liabilities		1,065.5	1,076.2
Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1,107.5	1,113
Accumulated Depreciation and Amortization		2,116	2,048.7
Regulatory Liabilities
Current Regulatory Liabilities		4.2	27.6
Noncurrent Regulatory Liabilities		506.2	514.2
Public Service Co Of Oklahoma [Member]
Regulatory Assets
Current Regulatory Assets		33.8	0
Noncurrent Regulatory Assets		340.2	214.8
Accumulated Depreciation and Amortization		1,272.7	1,352.5
Regulatory Liabilities
Current Regulatory Liabilities		0	76.1
Noncurrent Regulatory Liabilities		339.7	335.1
Southwestern Electric Power Co [Member]
Regulatory Assets
Current Regulatory Assets		8.4	4.1
Noncurrent Regulatory Assets		551.2	415.8
Accumulated Depreciation and Amortization		2,567.1	2,602.3
Regulatory Liabilities
Current Regulatory Liabilities		3.8	8.4
Noncurrent Regulatory Liabilities		438.9	448.8
Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		3,750.5	3,695.3
Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		627.8	637.1
Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1,065.5	1,076.2
Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		506	473.4
Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		339.7	335.1
Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		438.9	448.8
Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.8	40.8
Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	40.8
Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[1]	450.1	167.9
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[2]	39.3	57.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		64.7	59.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		100.8	1.3
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		118.1	13.4
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		95.9	5.9
Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		5,175.4	4,972.4
Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1,081.8	1,096.9
Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		851.9	745
Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1,006.7	1,111.7
Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		222.1	201.4
Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		455.3	409.9
Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		36.3
Advanced Metering Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.5	11.4
Remaining Refund Period		1 year
Advanced Metering Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.5	11.4
Remaining Refund Period		1 year
Advanced Metering Infrastructure Surcharge [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 17	21.2
Remaining Refund Period		4 years
Advanced Metering System [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 20.9	3.6
Remaining Recovery Period		4 years
Amos Plant Transfer Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	2
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[3],[4]	2,627.5	2,656.5
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	616.9	612.9
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5],[6]	236.5	350.6
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	432.4	422.3
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	279.3	275.5
Asset Removal Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[5]	409.7	396.8
Asset Removal Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[7]	18.7	38.1
Asset Removal Costs - Tanners Creek Plant Retirement [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		43
Asset Removal Costs - Tanners Creek Plant Retirement [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		43
Asset Retirement Obligation [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.6	2.4
Remaining Recovery Period		1 year
Asset Retirement Obligation - Arkansas, Louisiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2.7	1.7
Base Plan Funding Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0	1.3
Remaining Refund Period
Basic Transmission Cost Rider [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0.3	4.9
Remaining Refund Period		2 years
Basic Transmission Cost Rider [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.9	0
Remaining Recovery Period		2 years
Basic Transmission Cost Rider [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.9	0
Remaining Recovery Period		2 years
Capacity Costs - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.4	7.5
Remaining Recovery Period		1 year
Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1	1.2
Remaining Recovery Period		6 years
Carbon Capture and Storage Product Validation Facility [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.1	11.7
Remaining Recovery Period		4 years
Carbon Capture and Storage Product Validation Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.1	11.7
Remaining Recovery Period		4 years
Consumer Rate Relief - West Virginia [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 5.1	2.9
Remaining Refund Period		1 year
Cook Plant Nuclear Refueling Outage Levelization [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 75.2	26.8
Remaining Recovery Period		3 years
Cook Plant Nuclear Refueling Outage Levelization [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 75.2	26.8
Remaining Recovery Period		3 years
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.8	9.7
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		12.8	9.7
Cook Plant, Unit 2 Baffle Bolts - Indiana [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.3	6.6
Remaining Recovery Period		22 years
Cook Plant Uprate Project [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 36.3	0
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 4.2	29.1
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 4.2	27.6
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 3.8	84.8
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 0	0.3
Remaining Refund Period
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 0	76.1
Remaining Refund Period
Deferred Fuel Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Current Regulatory Liabilities		$ 3.8	8.4
Remaining Refund Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 61.4	38.9
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 6.2	27.3
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 13	7.5
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Current Regulatory Assets		$ 33.8	0
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 8.4	4.1
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 218.9	304.5
Remaining Recovery Period		2 years
Deferred Fuel Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 218.9	304.5
Remaining Recovery Period		2 years
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member]
Regulatory Assets
Current Regulatory Assets		$ 95.2	76.3
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Appalachian Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 62.2	59.6
Remaining Recovery Period		1 year
Deferred Fuel Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Current Regulatory Assets		$ 13.1	4.1
Remaining Recovery Period		1 year
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 132.9	113.3
Remaining Refund Period		46 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 38.8	35
Remaining Refund Period		20 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 48	46.3
Remaining Refund Period		38 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 7.3	8.5
Remaining Refund Period		14 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 12.6	14.7
Remaining Refund Period		42 years
Deferred Investment Tax Credits [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0.9	1
Remaining Refund Period		42 years
Deferred Asset Phase-In Rider [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 4.5	5.1
Remaining Refund Period		4 years
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.1	4.2
Deferred Cook Plant Life Cycle Management Project Costs - Indiana [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 4.6	0
Remaining Refund Period		3 years
Deferred Restructuring Costs - Louisiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.9	3.5
Remaining Recovery Period		2 years
Deferred Restructuring Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2.5	4.5
Remaining Recovery Period		2 years
Deferred System Reliability Rider Expenses [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.5	9.9
Remaining Recovery Period		1 year
Deferred System Reliability Rider Expenses [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 12.5	9.9
Remaining Recovery Period		1 year
Deferred Wind Power Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 2.1	11.8
Remaining Refund Period		1 year
Deferred Wind Power Costs - Virginia [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 2.1	11.8
Remaining Refund Period		1 year
Distribution Investment Rider [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2	12.3
Remaining Recovery Period		2 years
Distribution Investment Rider [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2	12.3
Remaining Recovery Period		2 years
Economic Development Rider [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0	5
Remaining Refund Period
Economic Development Rider [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.7	0
Remaining Recovery Period		2 years
Energy Efficiency Rate Adjustments Clause - Virginia [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.5	0
Remaining Refund Period		2 years
Enhanced Service Reliability Plan [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 21.7	8
Remaining Refund Period		2 years
Enhanced Service Reliability Plan [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 21.7	8
Remaining Refund Period		2 years
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 24.1	0
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		13.1	0
Environmental Controls Projects [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		11	0
Excess Asset Retirement Obligations For Nuclear Decommissioning Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	731.2	636.5
Excess Asset Retirement Obligations For Nuclear Decommissioning Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	731.2	636.5
Excess Earnings [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 10	10.6
Remaining Refund Period		37 years
Excess Earnings - Texas [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 2.7	2.7
Remaining Refund Period		37 years
Generation Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.5	5.2
Remaining Recovery Period		2 years
Generation Recovery Rider Costs - Arkansas [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.2	1.5
Remaining Refund Period		2 years
gridSMART Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.9	0
Remaining Refund Period		2 years
gridSMART Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 11.9	0
Remaining Refund Period		2 years
gridSMART Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.1	1.3
gridSMART Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	4.5
Remaining Recovery Period
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 320	288
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		64	59
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		74	69
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		76	82
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[9]	$ 1,575	1,385.3
Remaining Recovery Period		62 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[10]	$ 463.5	441.7
Remaining Recovery Period		26 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[11]	$ 302.6	246.8
Remaining Recovery Period		32 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets	[12]	$ 126.4	129
Remaining Recovery Period		28 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.3	6.1
Remaining Recovery Period		33 years
Income Taxes, Net [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 314.2	271.9
Remaining Recovery Period		34 years
Integrated Gasification Combined Cycle Preconstruction Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.6	10.9
Remaining Recovery Period		24 years
Integrated Gasification Combined Cycle Preconstruction Costs - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.4	9.6
Remaining Recovery Period		4 years
Litigation Settlement [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 7.6	8.6
Remaining Recovery Period		9 years
Louisiana Refundable Construction Financing Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 16.2	37.4
Remaining Refund Period		2 years
Louisiana Refundable Construction Financing Costs [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 16.2	37.4
Remaining Refund Period		2 years
Mitchell Plant Transfer [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.5	19.3
Remaining Recovery Period		24 years
Off-system Sales Margin Sharing - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 24.3	6.8
Remaining Recovery Period		2 years
Off-system Sales Margin Sharing - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 24.3	6.8
Remaining Recovery Period		2 years
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 96.7	0
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		96.7	0
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 201.9	358.7
Remaining Recovery Period		2 years
Ohio Capacity Deferral [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 201.9	358.7
Remaining Recovery Period		2 years
Ohio Distribution Decoupling [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 41.8	37.5
Remaining Recovery Period		2 years
Ohio Distribution Decoupling [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 41.8	37.5
Remaining Recovery Period		2 years
Ohio Transmission Cost Recovery Rider [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	12.3
Remaining Recovery Period
Ohio Transmission Cost Recovery Rider [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	12.3
Remaining Recovery Period
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 27.6	25.5
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.6	0
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.3	1
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.3	0.2
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		52.5	77.8
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.4	1.2
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.6	1.1
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.1	1
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.1	1.1
Other Regulatory Assets Approved for Recovery [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.9	1.3
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.3	0
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.5	0
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.8	0
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		29.1	22
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.6	0.6
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0.9	0
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	1.1
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		1.9	0.8
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		29.4	24.4
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	0.1
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.7	1.3
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.9	1
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.9	0.6
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Southwestern Electric Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.8	1.9
Other Regulatory Liabilities Approved for Payment [Member] | Regulatory Liabilities Currently Paying a Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		1.6	20.5
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.8	0.2
Other Regulatory Liabilities Pending Final Regulatory Determination [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0.2	0.2
OVEC Purchased Power [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets			0
OVEC Purchased Power [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 22.1
Remaining Recovery Period		2 years
OVEC Purchased Power [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 22.1	0
Remaining Recovery Period		2 years
Partnership with Ohio Contribution [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.4	2.4
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 34	5.3
Remaining Refund Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 29	1.5
Remaining Refund Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.2	13.1
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 49.9	33.3
Remaining Recovery Period		5 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.6	10.6
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.3	11.8
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3	1
Remaining Recovery Period		2 years
Peak Demand Reduction/Energy Efficiency - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	12.7
Peak Demand Reduction/Energy Efficiency - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.2	3.5
Remaining Recovery Period		4 years
PJM Expense - Indiana [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 4.2	0
Remaining Refund Period		2 years
PJM Expense - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	4.1
Remaining Recovery Period
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.3	7.6
Remaining Recovery Period		24 years
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 29.6	59.8
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		29.6	32.7
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	27.1
Plant Retirement Costs - Asset Retirement Obligation Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 48.9	58
Remaining Recovery Period		24 years
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.1	20.9
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		9.1	9.3
Plant Retirement Costs - Materials and Supplies [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		0	11.6
Plant Retirement Costs - Unrecovered Plant [Member]
Regulatory Assets
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Appalachian Power Co [Member]
Regulatory Assets
Accumulated Depreciation and Amortization		91
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		159.9	0
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		84.5	0
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		75.4	0
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 550.6	539.3
Remaining Recovery Period		28 years
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 85.4	86.5
Remaining Recovery Period		27 years
Plant Retirement Costs - Unrecovered Plant [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 252.8	260.3
Remaining Recovery Period		28 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 39.1	42.6
Remaining Recovery Period		5 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 17.4	19.6
Remaining Recovery Period		5 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 11.4	10.7
Remaining Recovery Period		5 years
Postemployment Benefits [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.8	7.3
Remaining Recovery Period		5 years
Provision for Regulatory Loss [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0	40.6
Provision for Regulatory Loss [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Pending Final Regulatory Determination [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		0	40.6
Rate Case Expense [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.4	1.2
Remaining Recovery Period		1 year
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1	0.3
Rate Case Expense - Texas [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.2	6.8
Remaining Recovery Period		2 years
Red Rock Generating Facility [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.1	9.3
Remaining Recovery Period		40 years
Red Rock Generating Facility [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.1	9.3
Remaining Recovery Period		40 years
Regional Transmission Organization Formation/Integration Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.6	2.1
Remaining Recovery Period		3 years
Regional Transmission Organization Formation/Integration Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1.2	1.5
Remaining Recovery Period		3 years
Regional Transmission Organization Formation/Integration Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2.5	3.1
Remaining Recovery Period		3 years
Regulatory Settlement [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0	9
Remaining Refund Period
River Transportation Division Expenses [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0	1.9
Remaining Refund Period
River Transportation Division Expenses [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.7	0
Remaining Recovery Period		1 year
Rockport Plant Dry Sorbent Injection System - Indiana [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.7	0.4
Remaining Refund Period		2 years
Rockport Plant Dry Sorbent Injection System - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 6.6	2.8
Shipe Road Transmission Project - FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		3.1	3.1
Spent Nuclear Fuel Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	44.2	43.4
Spent Nuclear Fuel Liability [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities	[8]	44.2	43.4
Storm Related Costs [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 5.3	1.3
Remaining Refund Period		2 years
Storm Related Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 25.1	24.2
Storm Related Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 15.3	8.8
Remaining Recovery Period		3 years
Storm Related Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.8	0
Remaining Recovery Period		3 years
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 25.9	18.2
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		20	12.3
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 58.7	94.6
Remaining Recovery Period		4 years
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	15.4
Storm Related Costs - Indiana [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.2	0
Remaining Refund Period		1 year
Storm Related Costs - Indiana [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	1.8
Remaining Recovery Period
Storm Related Costs - Virginia [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.6	8.8
Remaining Recovery Period		2 years
Storm Related Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 47.8	63.5
Remaining Recovery Period		4 years
Stranded Costs on Abandoned Plants [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	3.9
SPP Base Plan Fees [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.7	0
Remaining Recovery Period		2 years
SPP Base Plan Fees [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.7	0
Remaining Recovery Period		2 years
Texas Meter Replacement Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 99.9	90.4
Remaining Recovery Period		11 years
Texas Meter Replacement Costs [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 50.1	35.8
Remaining Recovery Period		8 years
Transition Charges [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 40.5	46.5
Remaining Refund Period		11 years
Transmission Agreement Phase-In - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	1.7
Remaining Recovery Period
Transmission Cost Recovery Factor [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 5.3	9.9
Remaining Recovery Period		1 year
Transmission Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 38.7	74.6
Remaining Recovery Period		2 years
Transmission Rate Adjustment Clause - Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 38.7	74.6
Remaining Recovery Period		2 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 137.8	148.7
Remaining Recovery Period		29 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 97.2	101.5
Remaining Recovery Period		29 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 10.7	12
Remaining Recovery Period		16 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 9.1	10.4
Remaining Recovery Period		22 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 5.8	6.8
Remaining Recovery Period		16 years
Unamortized Loss on Reacquired Debt [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 5.4	6
Remaining Recovery Period		27 years
Uncollected Accounts - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 2.7	3.5
Remaining Recovery Period		4 years
United Mine Workers of America Pension Withdrawal [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 20.2	14.4
Remaining Recovery Period		6 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 6.2	33.8
Remaining Refund Period		2 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Appalachian Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 1.3	8.4
Remaining Refund Period		2 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Indiana Michigan Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 2.4	7.1
Remaining Refund Period		2 years
Unrealized Gain on Forward Commitments [Member] | Regulatory Liabilities Currently Not Paying Return [Member] | Regulatory Liabilities Approved for Payment [Member] | Ohio Power Co [Member]
Regulatory Liabilities
Noncurrent Regulatory Liabilities		$ 0	15.3
Remaining Refund Period
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 119.1	10.7
Remaining Recovery Period		16 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.1	3.2
Remaining Recovery Period		2 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 118.6	0
Remaining Recovery Period		16 years
Unrealized Loss on Forward Commitments [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0.3	5.5
Remaining Recovery Period		1 year
Vegetation Management [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 31.4	36.9
Remaining Recovery Period		5 years
Vegetation Management [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 0	4.5
Remaining Recovery Period
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 31.4	31.2
Remaining Recovery Period		5 years
West Virginia Delayed Customer Billing [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 19.5	0
Remaining Recovery Period		2 years
West Virginia Delayed Customer Billing [Member] | Regulatory Assets Currently Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 18.1	0
Remaining Recovery Period		2 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 37.2	41.8
Remaining Recovery Period		8 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.2	9.2
Remaining Recovery Period		8 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 8.3	9.3
Remaining Recovery Period		8 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 3.9	4.4
Remaining Recovery Period		8 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.3	4.8
Remaining Recovery Period		8 years
Other Postretirement Benefit Plans [Member] | Medicare Subsidy - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 4.7	5.3
Remaining Recovery Period		8 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 1,516.2	1,410.5
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Appalachian Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 221.4	217.6
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Indiana Michigan Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 141.9	126.4
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Ohio Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 225.2	219.4
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Public Service Co Of Oklahoma [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 98.1	95.1
Remaining Recovery Period		12 years
Other Postretirement Benefit Plans [Member] | Pension Costs [Member] | Regulatory Assets Currently Not Earning a Return [Member] | Regulatory Assets Approved for Recovery [Member] | Southwestern Electric Power Co [Member]
Regulatory Assets
Noncurrent Regulatory Assets		$ 119.8	$ 108.9
Remaining Recovery Period		12 years
[1]	As of December 31, 2016, APCo has deferred a total of $91 million as charges to accumulated depreciation related to certain plant retirements in 2015. APCo intends to address the need for depreciation rate increases in a subsequent base rate cases.
[2]	(a)As of December 31, 2016, APCo has also deferred $91 million as a charge to accumulated depreciation related to the net book value of certain plants retired in 2015, primarily in its Virginia jurisdiction. These plants were normal retirements and not abandonments. APCo intends to address the need for an increase in its Virginia depreciation rates in March 2020, as part of its 2018-2019 Virginia biennial filing.
[3]	As of December 31, 2016, I&M also charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases.
[4]	Relieved as removal costs are incurred.
[5]	Relieved as removal costs are incurred.
[6]	As of December 31, 2016, I&M has charged $43 million to asset removal costs related to various Tanners Creek Plant related assets, primarily related to the net book value of ARO assets. The Indiana and Michigan retail jurisdictions of I&M have increased depreciation rates on Rockport Plant to recover the net book value of Tanners Creek Plant that was retired in 2015. I&M intends to address the need for increases in depreciation rates to recover the deferral in its next Indiana and Michigan base rate cases.
[7]	As a regulated entity, removal costs accrued are typically recorded as regulatory liabilities when removal costs accrued exceed actual removal costs incurred. The asset removal costs liability is relieved as removal costs are incurred. As of December 31, 2016, KPCo’s accumulated actual removal cost incurred exceeded accumulated removal cost accrued, creating an asset balance. As a result, the balance was reclassified to a regulatory asset. Within the next two years, KPCo’s removal costs accrued are expected to exceed removal costs incurred resulting in a regulatory liability.
[8]	Relieved when plant is decommissioned.
[9]	Includes $320 million and $288 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates.
[10]	Includes $64 million and $59 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates.
[11]	Includes $74 million and $69 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates.
[12]	Includes $76 million and $82 million as of December 31, 2016 and 2015, respectively, expected to be recovered in formula rates.

Commitments, Guarantees and C62

Commitments, Guarantees and Contingencies (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Contractual Commitments
Less than 1 year		$ 1,623.3
For 2-3 years		1,878.7
For 4-5 years		1,424.6
After 5 years		2,112
Total Contractual Commitments		7,038.6
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities		3,500
Disposal, Assessed Fees and Related Interest	[1]	266.3	$ 265.6
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		149.7
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
Equity Method Investee [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Potential Amount of Future Payments Associated with Guarantee		75
Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[2],[3]	1,407.8
For 2-3 years	[2],[3]	1,441.6
For 4-5 years	[2],[3]	985.5
After 5 years	[2],[3]	371.8
Total Contractual Commitments	[2],[3]	4,206.7
Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		215.5
For 2-3 years		437.1
For 4-5 years		439.1
After 5 years		1,740.2
Total Contractual Commitments		2,831.9
Appalachian Power Co [Member]
Contractual Commitments
Less than 1 year		524.9
For 2-3 years		502.7
For 4-5 years		487.4
After 5 years		431.9
Total Contractual Commitments		1,946.9
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] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	491.5
For 2-3 years	[3]	433.8
For 4-5 years	[3]	415
After 5 years	[3]	1.2
Total Contractual Commitments	[3]	1,341.5
Appalachian Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		33.4
For 2-3 years		68.9
For 4-5 years		72.4
After 5 years		430.7
Total Contractual Commitments		605.4
Indiana Michigan Power Co [Member]
Contractual Commitments
Less than 1 year		411.2
For 2-3 years		525.5
For 4-5 years		471.4
After 5 years		763.6
Total Contractual Commitments		2,171.7
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Disposal, Assessed Fees and Related Interest	[1]	266.3	265.6
Indiana Michigan Power Co [Member] | Letters of Credit [Member]
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported		77
Bilateral Letters of Credit		77.9
Indiana Michigan Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	292.7
For 2-3 years	[3]	277.8
For 4-5 years	[3]	221.9
After 5 years	[3]	266.1
Total Contractual Commitments	[3]	1,058.5
Indiana Michigan Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		118.5
For 2-3 years		247.7
For 4-5 years		249.5
After 5 years		497.5
Total Contractual Commitments		1,113.2
Ohio Power Co [Member]
Contractual Commitments
Less than 1 year		27.1
For 2-3 years		55.9
For 4-5 years		58.6
After 5 years		442.6
Total Contractual Commitments		584.2
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit Under Uncommitted Facilities [Abstract]
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility		0.6
Ohio Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		27.1
For 2-3 years		55.9
For 4-5 years		58.6
After 5 years		442.6
Total Contractual Commitments		584.2
Public Service Co Of Oklahoma [Member]
Contractual Commitments
Less than 1 year		154.5
For 2-3 years		237.2
For 4-5 years		209.7
After 5 years		297.2
Total Contractual Commitments		898.6
Public Service Co Of Oklahoma [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	63.9
For 2-3 years	[3]	55.5
For 4-5 years	[3]	29.8
After 5 years	[3]	14.9
Total Contractual Commitments	[3]	164.1
Public Service Co Of Oklahoma [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		90.6
For 2-3 years		181.7
For 4-5 years		179.9
After 5 years		282.3
Total Contractual Commitments		734.5
Southwestern Electric Power Co [Member]
Contractual Commitments
Less than 1 year		131
For 2-3 years		206.3
For 4-5 years		132.2
After 5 years		198.5
Total Contractual Commitments		668
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		69
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent		73
Amount Collected, Rider Mine Close Other Assets Noncurrent		4
Southwestern Electric Power Co [Member] | Fuel Purchase Contracts [Member]
Contractual Commitments
Less than 1 year	[3]	98.4
For 2-3 years	[3]	139.7
For 4-5 years	[3]	69.7
After 5 years	[3]	22.6
Total Contractual Commitments	[3]	330.4
Southwestern Electric Power Co [Member] | Energy and Capacity Purchase Contracts [Member]
Contractual Commitments
Less than 1 year		32.6
For 2-3 years		66.6
For 4-5 years		62.5
After 5 years		175.9
Total Contractual Commitments		337.6
Comprehensive Environmental Response Compensation and Liabilities Act and State Remediation [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision		7
Comprehensive Environmental Response Compensation and Liabilities Act and State Remediation [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision		7
Decommissioning and Low Level Waste Accumulation Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Cost of Decommissioning and Disposal of Radioactive Waste		1,600
Additional Ongoing Costs for Post Decommissioning Storage of SNF		5
Subsequent Decommissioning of the Spent Fuel Storage Facility		57
Amount Recovered in Rates for Decommissioning Costs		9	9	$ 9
Decommissioning Fund Investments, Fair Value		1,900	1,800
Decommissioning and Low Level Waste Accumulation Disposal [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Cost of Decommissioning and Disposal of Radioactive Waste		1,600
Additional Ongoing Costs for Post Decommissioning Storage of SNF		5
Subsequent Decommissioning of the Spent Fuel Storage Facility		57
Amount Recovered in Rates for Decommissioning Costs		9	9	9
Decommissioning Fund Investments, Fair Value		1,900	1,800
Nuclear Incident Liability [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Insurance Coverage for Property Damage, Decommissioning and Decontamination		3,000
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		1,500
Contingent Financial Obligation for Mutual Iinsurance		50
Insurance Protection for Public Liability Arising from a Nuclear Incident		13,400
Commercially Available Insurance		375
Remainder of the Liability Provided by a Deferred Premium Assessment		127
Deferred Premium Assessment Annual Payment		19
Assessed Amount per Nuclear Incident		255
Annual Installments		38
Commercially Available Insurance for Catastrophic Nature		375
Commercially Available Insurance for Catastrophic Nature Beginning in 2017		450
Liability Coverage Under the Price-Anderson Act		13,000
Nuclear Incident Liability [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Insurance Coverage for Property Damage, Decommissioning and Decontamination		3,000
Coverage for Property Damage, Decommissioning and Decontamination for a Nonnuclear Incident		1,500
Contingent Financial Obligation for Mutual Iinsurance		50
Insurance Protection for Public Liability Arising from a Nuclear Incident		13,400
Commercially Available Insurance		375
Remainder of the Liability Provided by a Deferred Premium Assessment		127
Deferred Premium Assessment Annual Payment		19
Assessed Amount per Nuclear Incident		255
Annual Installments		38
Commercially Available Insurance for Catastrophic Nature		375
Commercially Available Insurance for Catastrophic Nature Beginning in 2017		450
Liability Coverage Under the Price-Anderson Act		13,000
Spent Nuclear Fuel Disposal [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		311	309
Recovery of Spent Nuclear Fuel Storage Costs		6	13	22
Current Amount Recoverable from the Federal Government		22
Noncurrent Amount Recoverable from the Federal Government		5
Spent Nuclear Fuel Disposal [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition		311	309
Recovery of Spent Nuclear Fuel Storage Costs		6	$ 13	$ 22
Current Amount Recoverable from the Federal Government		22
Noncurrent Amount Recoverable from the Federal Government		5
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
[1]	Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6).
[2]	Excludes approximately $1.1 billion of fuel purchase contracts related to plants Held for Sale. See Note 7.
[3]	Represents contractual commitments to purchase coal, natural gas, uranium and other consumables as fuel for electric generation along with related transportation of the fuel.

Dispositions, Assets and Liab63

Dispositions, Assets and Liabilities Held for Sale and Impairments (Details) - USD ($) $ in Millions		3 Months Ended									12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016		Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Make Whole Premium on Extinguishment of Long-term Debt											$ 0	$ 92.7	$ 0
Disposal Group, Balance Sheet Disclosure [Abstract]
Total Assets from Discontinued Operations on the Balance Sheet		$ 1,951.2									1,951.2
Total Liabilities from Discontinued Operations on the Balance Sheet		235.9									235.9
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income				$ (2.5)	[1]	$ 265.5	[2]	$ 7.8	$ (0.1)	$ 10.5	(2.5)	283.7	47.5
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges											2,267.8	0	0
Corporate and Other [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Other Revenues												447.1	641.6
Other Operation Expense												321.3	459.5
Maintenance Expense												21.5	32.6
Depreciation and Amortization Expense												26.9	31.5
Taxes Other Than Income Taxes												10.6	14.2
Total Expenses												380.3	537.8
Other Expense												(16.9)	(17.1)
Pretax Income of Discontinued Operations												49.9	86.7
Income Tax Expense												19.4	39
Equity Earnings of Unconsolidated Subsidiaries												(0.1)	(0.2)
Income from Discontinued Operations of AEPRO												30.4	47.5
Gain on Sale of Discontinued Operations												240.1	0
Income Tax Expense (Benefit)												(13.2)	0
Gain on Sale of Discontinued Operations, Net of Tax												253.3	0
Total Income on Discontinued Operations as Presented on the Statements of Income												283.7	47.5
Vertically Integrated Utilities [Member]
Disposal Group, Balance Sheet Disclosure [Abstract]
Total Assets from Discontinued Operations on the Balance Sheet		0									0
Total Liabilities from Discontinued Operations on the Balance Sheet		0									0
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income											0	0	0
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges											10.5
Vertically Integrated Utilities [Member] | Tanners Creek Plant Units 1 Through 4 [Member]
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Payment on Sale of the Plant											92
Generation and Marketing [Member]
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Cash Proceeds from Sale of Disposition Plants, Net											2,200
Pretax Income (Loss) of Disposal Group											375	451	444
Disposal Group, Balance Sheet Disclosure [Abstract]
Fuel		145.5									145.5
Materials and Supplies		49.4									49.4
Property, Plant and Equipment - Net		1,756.2									1,756.2
Other Classes of Assets That Are Not Major		0.1									0.1
Total Assets from Discontinued Operations on the Balance Sheet		1,951.2									1,951.2
Long-term Debt		134.8									134.8
Waterford Plant Upgrade Liability		52.2									52.2
Asset Retirement Obligations		36.7									36.7
Other Classes of Liabilities That Are Not Major		12.2									12.2
Total Liabilities from Discontinued Operations on the Balance Sheet		235.9									235.9
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income											0	0	0
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges											2,257.3
Generation and Marketing [Member] | Muskingum River Plant [Member]
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Payment on Sale of the Plant												48
Gain on Sale of Muskingum River Plant												32
Appalachian Power Co [Member]
Dispositions, Assets and Liabilities Held for Sale and Impairments (Textuals) [Abstract]
Make Whole Premium on Extinguishment of Long-term Debt											0	92.7	0
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income				0		0		0	0	0
Indiana Michigan Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income				0		0		0	0	0
Asset Impairment Charges [Abstract]
Asset Impairments and Other Related Charges											10.5	$ 0	$ 0
Ohio Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income				0		0		0	0	0
Public Service Co Of Oklahoma [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income				0		0		0	0	0
Southwestern Electric Power Co [Member]
Disposal Group, Including Discontinued Operation, Income Statement Disclosures [Abstract]
Total Income on Discontinued Operations as Presented on the Statements of Income				$ 0		$ 0		$ 0	$ 0	$ 0
I&M Price River Coal Reserves [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Public Utilities, Property, Plant and Equipment, Net		11									11
Merchant Coal-Fired Generation Assets [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure		0									0
Public Utilities, Property, Plant and Equipment, Net		2,139.4									2,139.4
Asset Impairments and Other Related Charges		3	$ 2,139.4
Trent and Desert Sky Wind Farms [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure		46									46
Public Utilities, Property, Plant and Equipment, Net		118.7									118.7
Asset Impairments and Other Related Charges			72.7
Coal Reserves [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure		3.8									3.8
Public Utilities, Property, Plant and Equipment, Net	[3]	56.6									56.6
Asset Impairments and Other Related Charges	[3]		52.8
Total Impaired Assets [Member] | Generation and Marketing [Member]
Asset Impairment Charges [Abstract]
Property, Plant, and Equipment, Fair Value Disclosure		49.8									49.8
Public Utilities, Property, Plant and Equipment, Net		$ 2,314.7									$ 2,314.7
Asset Impairments and Other Related Charges			$ 2,264.9
[1]	Includes final accounting adjustment for sale of AEPRO (see Note 7).
[2]	Includes sale of AEPRO (see Note 7).
[3]	(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 1 (Details)

Benefit Plans 1 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		$ 2,085.1	$ 2,106.6
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(774.6)	(890.6)
Appalachian Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		133.3	113.7
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(64.5)	(57.7)
Indiana Michigan Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		121.5	140.9
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(120.4)	(119.4)
Ohio Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		295.5	259.6
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(83.9)	(30.7)
Public Service Co Of Oklahoma [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		10	6.4
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(11.2)	(13.7)
Southwestern Electric Power Co [Member]
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		99.9	75.8
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		$ (9.7)	$ (49.3)
Pension Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.05%	4.30%
Rate of Compensation Increase	[1]	4.75%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.75%	4.80%	4.85%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 4,992.9	$ 5,224.9
Service Cost		85.8	93.5	$ 71.9
Interest Cost		211.6	205.3	221
Actuarial (Gain) Loss		142.7	(200.6)
Benefit Payments		(347.2)	(330.2)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		5,085.8	4,992.9	5,224.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		4,767.6	4,967.5
Actual Gain (Loss) on Plan Assets		315.5	32.4
Company Contributions		91.4	97.9
Participant Contributions		0	0
Benefit Payments		(347.2)	(330.2)
Fair Value of Plan Assets as of December 31		4,827.3	4,767.6	$ 4,967.5
Funded (Underfunded) Status as of December 31		(258.5)	(225.3)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(5.9)	(6.3)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(252.6)	(219)
Funded (Underfunded) Status		(258.5)	(225.3)
Components
Net Actuarial Loss		1,569.8	1,546.1
Prior Service Cost (Credit)		1	3.3
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		107.5	41.8
Amortization of Actuarial Gain (Loss)		(83.8)	(107.1)
Amortization of Prior Service Credit (Cost)		(2.3)	(2.2)
Change for the Year		$ 21.4	$ (67.5)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.75%	4.80%
Pension Plans [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 1,415.6	$ 1,385.2
Pension Plans [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		54.4	57.5
Pension Plans [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 100.8	$ 106.7
Pension Plans [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.05%	4.30%
Rate of Compensation Increase	[1]	4.55%	4.45%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.55%	4.45%	4.60%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 653.4	$ 702.8
Service Cost		8.1	8.7	$ 7
Interest Cost		27.2	26.7	29.6
Actuarial (Gain) Loss		9.2	(41.4)
Benefit Payments		(43.9)	(43.4)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		654	653.4	702.8
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		603.2	642.3
Actual Gain (Loss) on Plan Assets		38.3	(5.7)
Company Contributions		8.8	10
Participant Contributions		0	0
Benefit Payments		(43.9)	(43.4)
Fair Value of Plan Assets as of December 31		606.4	603.2	$ 642.3
Funded (Underfunded) Status as of December 31		(47.6)	(50.2)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(47.6)	(50.2)
Funded (Underfunded) Status		(47.6)	(50.2)
Components
Net Actuarial Loss		216.2	220.8
Prior Service Cost (Credit)		0.2	0.3
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		6.2	(0.3)
Amortization of Actuarial Gain (Loss)		(10.8)	(13.9)
Amortization of Prior Service Credit (Cost)		(0.1)	(0.2)
Change for the Year		$ (4.7)	$ (14.4)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.55%	4.45%
Pension Plans [Member] | Appalachian Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 213.7	$ 218.3
Pension Plans [Member] | Appalachian Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1	1
Pension Plans [Member] | Appalachian Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 1.7	$ 1.8
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.05%	4.30%
Rate of Compensation Increase	[1]	4.80%	4.75%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.80%	4.80%	4.90%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 591.5	$ 617.9
Service Cost		12.2	12.9	$ 10
Interest Cost		25.3	24.5	26.3
Actuarial (Gain) Loss		20.1	(28.4)
Benefit Payments		(37.5)	(35.4)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		611.6	591.5	617.9
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		570	591.7
Actual Gain (Loss) on Plan Assets		40.6	(0.9)
Company Contributions		13	14.6
Participant Contributions		0	0
Benefit Payments		(37.5)	(35.4)
Fair Value of Plan Assets as of December 31		586.1	570	$ 591.7
Funded (Underfunded) Status as of December 31		(25.5)	(21.5)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		(25.5)	(21.5)
Funded (Underfunded) Status		(25.5)	(21.5)
Components
Net Actuarial Loss		133.2	130
Prior Service Cost (Credit)		0.2	0.3
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		13.2	4.7
Amortization of Actuarial Gain (Loss)		(10)	(12.6)
Amortization of Prior Service Credit (Cost)		(0.1)	(0.2)
Change for the Year		$ 3.1	$ (8.1)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.80%	4.75%
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 128.2	$ 125.3
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1.8	1.8
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 3.4	$ 3.2
Pension Plans [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.05%	4.30%
Rate of Compensation Increase	[1]	4.85%	4.85%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.85%	4.80%	5.00%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 497.5	$ 526.3
Service Cost		6.5	6.7	$ 5.2
Interest Cost		20.6	20.3	22.1
Actuarial (Gain) Loss		4.7	(19.5)
Benefit Payments		(36.4)	(36.3)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		492.9	497.5	526.3
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		472.1	498.5
Actual Gain (Loss) on Plan Assets		30.9	2.2
Company Contributions		7.2	7.7
Participant Contributions		0	0
Benefit Payments		(36.4)	(36.3)
Fair Value of Plan Assets as of December 31		473.8	472.1	$ 498.5
Funded (Underfunded) Status as of December 31		(19.1)	(25.4)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(19.1)	(25.4)
Funded (Underfunded) Status		(19.1)	(25.4)
Components
Net Actuarial Loss		215.4	222
Prior Service Cost (Credit)		0.1	0.2
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		1.5	5.8
Amortization of Actuarial Gain (Loss)		(8.1)	(10.5)
Amortization of Prior Service Credit (Cost)		(0.1)	(0.2)
Change for the Year		$ (6.7)	$ (4.9)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.85%	4.85%
Pension Plans [Member] | Ohio Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 215.5	$ 222.2
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.05%	4.30%
Rate of Compensation Increase	[1]	4.90%	4.85%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.90%	4.80%	4.90%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 265.4	$ 285.4
Service Cost		6.2	6.4	$ 5.2
Interest Cost		11.2	10.9	12.1
Actuarial (Gain) Loss		3.1	(17.9)
Benefit Payments		(19.2)	(19.4)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		266.7	265.4	285.4
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		262.1	275.5
Actual Gain (Loss) on Plan Assets		17.3	0.1
Company Contributions		5.8	5.9
Participant Contributions		0	0
Benefit Payments		(19.2)	(19.4)
Fair Value of Plan Assets as of December 31		266	262.1	$ 275.5
Funded (Underfunded) Status as of December 31		(0.7)	(3.3)
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		1.6	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.2)	(0.2)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(2.1)	(3.1)
Funded (Underfunded) Status		(0.7)	(3.3)
Components
Net Actuarial Loss		91	94.1
Prior Service Cost (Credit)		0	0.3
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		1.3	(2.9)
Amortization of Actuarial Gain (Loss)		(4.4)	(5.7)
Amortization of Prior Service Credit (Cost)		(0.3)	(0.2)
Change for the Year		$ (3.4)	$ (8.8)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.90%	4.85%
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 91	$ 94.4
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.05%	4.30%
Rate of Compensation Increase	[1]	4.75%	4.80%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		6.00%	6.00%	6.00%
Rate of Compensation Increase	[2]	4.75%	4.80%	4.85%
Change in Benefit Obligation
Benefit Obligation as of January 1		$ 282.8	$ 298.2
Service Cost		8.1	8.3	$ 6.6
Interest Cost		12.4	11.8	12.7
Actuarial (Gain) Loss		13.8	(16.2)
Benefit Payments		(20.5)	(19.3)
Participant Contributions		0	0
Medicare Subsidy		0	0
Benefit Obligation as of December 31		296.6	282.8	298.2
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		280.6	290.2
Actual Gain (Loss) on Plan Assets		18.8	1.6
Company Contributions		8.4	8.1
Participant Contributions		0	0
Benefit Payments		(20.5)	(19.3)
Fair Value of Plan Assets as of December 31		287.3	280.6	$ 290.2
Funded (Underfunded) Status as of December 31		(9.3)	(2.2)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		0	0
Other Current Liabilities - Accrued Short-term Benefit Liability		(0.1)	(0.1)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(9.2)	(2.1)
Funded (Underfunded) Status		(9.3)	(2.2)
Components
Net Actuarial Loss		103.8	97.1
Prior Service Cost (Credit)		0.1	0.4
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		11.5	(1.8)
Amortization of Actuarial Gain (Loss)		(4.8)	(6)
Amortization of Prior Service Credit (Cost)		(0.3)	(0.3)
Change for the Year		$ 6.4	$ (8.1)
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase	[1]	4.75%	4.80%
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 103.9	$ 97.5
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		0	0
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 0	$ 0
Pension Plans [Member] | Minimum [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Minimum [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		3.50%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		3.50%
Pension Plans [Member] | Maximum [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Pension Plans [Member] | Maximum [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Rate of Compensation Increase		12.00%
Benefit Plans (Textuals) [Abstract]
Rate of Compensation Increase		12.00%
Other Postretirement Benefit Plans [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.10%	4.30%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		7.00%	6.75%	6.75%
Health Care Trend Rates
Initial		7.00%	6.25%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 3.1
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(2.3)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		58.8
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(50.7)
Change in Benefit Obligation
Benefit Obligation as of January 1		1,450.6	$ 1,439
Service Cost		10.2	12.2	$ 14.2
Interest Cost		60.9	56.8	67.2
Actuarial (Gain) Loss		17.3	37.2
Benefit Payments		(130.2)	(128.7)
Participant Contributions		37.8	33.3
Medicare Subsidy		0.8	0.8
Benefit Obligation as of December 31		1,447.4	1,450.6	1,439
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		1,577.4	1,693.9
Actual Gain (Loss) on Plan Assets		56	(34)
Company Contributions		4.9	12.9
Participant Contributions		37.8	33.3
Benefit Payments		(130.2)	(128.7)
Fair Value of Plan Assets as of December 31		1,545.9	1,577.4	$ 1,693.9
Funded (Underfunded) Status as of December 31		98.5	126.8
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		154.5	185.8
Other Current Liabilities - Accrued Short-term Benefit Liability		(3)	(3.3)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(53)	(55.7)
Funded (Underfunded) Status		98.5	126.8
Components
Net Actuarial Loss		614.4	577.4
Prior Service Cost (Credit)		(485.4)	(554.4)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		68.4	176.3
Amortization of Actuarial Gain (Loss)		(31.4)	(18.8)
Amortization of Prior Service Credit (Cost)		69	69.1
Change for the Year		106	226.6
Other Postretirement Benefit Plans [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		90.4	15.1
Other Postretirement Benefit Plans [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		13.5	2.8
Other Postretirement Benefit Plans [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 25.1	$ 5.1
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.10%	4.30%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		7.00%	6.75%	6.75%
Health Care Trend Rates
Initial		7.00%	6.25%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.6
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.5)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		12.6
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(10.6)
Change in Benefit Obligation
Benefit Obligation as of January 1		262.2	$ 267.1
Service Cost		1	1.1	$ 1.4
Interest Cost		10.8	10.3	12.8
Actuarial (Gain) Loss		(0.2)	2.5
Benefit Payments		(24.8)	(24.7)
Participant Contributions		6.4	5.7
Medicare Subsidy		0.2	0.2
Benefit Obligation as of December 31		255.6	262.2	267.1
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		256.7	280.6
Actual Gain (Loss) on Plan Assets		5.9	(7.7)
Company Contributions		2.7	2.8
Participant Contributions		6.4	5.7
Benefit Payments		(24.8)	(24.7)
Fair Value of Plan Assets as of December 31		246.9	256.7	$ 280.6
Funded (Underfunded) Status as of December 31		(8.7)	(5.5)
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		25.2	30.8
Other Current Liabilities - Accrued Short-term Benefit Liability		(2.4)	(2.6)
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		(31.5)	(33.7)
Funded (Underfunded) Status		(8.7)	(5.5)
Components
Net Actuarial Loss		92.9	86.9
Prior Service Cost (Credit)		(70.5)	(80.6)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		11.4	24.7
Amortization of Actuarial Gain (Loss)		(5.4)	(3.6)
Amortization of Prior Service Credit (Cost)		10.1	10
Change for the Year		16.1	31.1
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		7.7	(0.7)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		5.1	2.4
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 9.6	$ 4.6
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.10%	4.30%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		7.00%	6.75%	6.75%
Health Care Trend Rates
Initial		7.00%	6.25%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.3
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.2)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		5.6
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(4.9)
Change in Benefit Obligation
Benefit Obligation as of January 1		166.3	$ 161.7
Service Cost		1.5	1.6	$ 1.9
Interest Cost		7	6.4	7.6
Actuarial (Gain) Loss		3.8	7.7
Benefit Payments		(15.7)	(15.2)
Participant Contributions		4.6	4
Medicare Subsidy		0.1	0.1
Benefit Obligation as of December 31		167.6	166.3	161.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		189	202.4
Actual Gain (Loss) on Plan Assets		8.7	(2.3)
Company Contributions		0	0.1
Participant Contributions		4.6	4
Benefit Payments		(15.7)	(15.2)
Fair Value of Plan Assets as of December 31		186.6	189	$ 202.4
Funded (Underfunded) Status as of December 31		19	22.7
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		19	22.7
Deferred Credits and Other Noncurrent Liabilities - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		19	22.7
Components
Net Actuarial Loss		81.3	77.1
Prior Service Cost (Credit)		(66.3)	(75.7)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		7.9	24.7
Amortization of Actuarial Gain (Loss)		(3.7)	(2)
Amortization of Prior Service Credit (Cost)		9.4	9.4
Change for the Year		13.6	32.1
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		13.7	1.1
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		0.5	0.1
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 0.8	$ 0.2
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.10%	4.30%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		7.00%	6.75%	6.75%
Health Care Trend Rates
Initial		7.00%	6.25%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.2
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.2)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		5.5
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(4.8)
Change in Benefit Obligation
Benefit Obligation as of January 1		168.6	$ 164.7
Service Cost		0.8	0.9	$ 1
Interest Cost		7	6.4	7.6
Actuarial (Gain) Loss		(1)	8.7
Benefit Payments		(16.2)	(16.3)
Participant Contributions		4.7	4.3
Medicare Subsidy		0.1	(0.1)
Benefit Obligation as of December 31		164	168.6	164.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		191.6	206.2
Actual Gain (Loss) on Plan Assets		2.5	(2.6)
Company Contributions		0	0
Participant Contributions		4.7	4.3
Benefit Payments		(16.2)	(16.3)
Fair Value of Plan Assets as of December 31		182.6	191.6	$ 206.2
Funded (Underfunded) Status as of December 31		18.6	23
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		18.6	23
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		18.6	23
Components
Net Actuarial Loss		58.2	52.6
Prior Service Cost (Credit)		(48.5)	(55.4)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		9.4	24
Amortization of Actuarial Gain (Loss)		(3.8)	(2.1)
Amortization of Prior Service Credit (Cost)		6.9	7
Change for the Year		12.5	28.9
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 9.7	$ (2.8)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.10%	4.30%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		7.00%	6.75%	6.75%
Health Care Trend Rates
Initial		7.00%	6.25%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.1
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.1)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		2.6
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(2.3)
Change in Benefit Obligation
Benefit Obligation as of January 1		77.7	$ 76.7
Service Cost		0.6	0.7	$ 0.8
Interest Cost		3.3	3	3.6
Actuarial (Gain) Loss		1	2.4
Benefit Payments		(7.2)	(7.1)
Participant Contributions		2.2	1.9
Medicare Subsidy		0	0.1
Benefit Obligation as of December 31		77.6	77.7	76.7
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		88.3	96
Actual Gain (Loss) on Plan Assets		3.1	(2.5)
Company Contributions		0	0
Participant Contributions		2.2	1.9
Benefit Payments		(7.2)	(7.1)
Fair Value of Plan Assets as of December 31		86.4	88.3	$ 96
Funded (Underfunded) Status as of December 31		8.8	10.6
Benefit Amounts Recognized on the Balance Sheets
Employee Benefits and Pension Assets - Prepaid Benefit Costs		8.8	10.6
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		8.8	10.6
Components
Net Actuarial Loss		37.3	35.2
Prior Service Cost (Credit)		(30.2)	(34.5)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		3.9	10.9
Amortization of Actuarial Gain (Loss)		(1.8)	(1)
Amortization of Prior Service Credit (Cost)		4.3	4.3
Change for the Year		6.4	14.2
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 7.1	$ 0.7
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Actuarial Assumptions for Benefit Obligations
Discount Rate		4.10%	4.30%
Actuarial Assumptions for Net Periodic Benefit Costs
Discount Rate		4.30%	4.00%	4.70%
Expected Return on Plan Assets		7.00%	6.75%	6.75%
Health Care Trend Rates
Initial		7.00%	6.25%
Ultimate		5.00%	5.00%
Year Ultimate Reached		2,024	2,020
Effect of a 1% Change in Assumed Health Care Cost Trend Rates for the OPEB Health Care Plans
Effect of 1% Increase on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		$ 0.1
Effect of 1% Decrease on Total Service and Interest Cost Components of Net Periodic Postretirement Health Care Benefit Cost		(0.1)
Effect of 1% Increase on the Health Care Component of the Accumulated Postretirement Benefit Obligation		2.9
Effect of 1% Decrease on the Health Care Component of the Accumulated Postretirement Benefit Obligation		(2.6)
Change in Benefit Obligation
Benefit Obligation as of January 1		86.1	$ 85
Service Cost		0.8	0.8	$ 1
Interest Cost		3.6	3.4	4
Actuarial (Gain) Loss		1.5	2.1
Benefit Payments		(7.5)	(7.4)
Participant Contributions		2.4	2.1
Medicare Subsidy		0	0.1
Benefit Obligation as of December 31		86.9	86.1	85
Change in Fair Value of Plan Assets
Fair Value of Plan Assets as of January 1		97.8	106.4
Actual Gain (Loss) on Plan Assets		4.1	(3.3)
Company Contributions		0	0
Participant Contributions		2.4	2.1
Benefit Payments		(7.5)	(7.4)
Fair Value of Plan Assets as of December 31		96.8	97.8	$ 106.4
Funded (Underfunded) Status as of December 31		9.9	11.7
Benefit Amounts Recognized on the Balance Sheets
Deferred Charges and Other Noncurrent Assets - Prepaid Benefit Costs		9.9	11.7
Other Current Liabilities - Accrued Short-term Benefit Liability		0	0
Employee Benefits and Pension Obligations - Accrued Long-term Benefit Liability		0	0
Funded (Underfunded) Status		9.9	11.7
Components
Net Actuarial Loss		45.4	43.3
Prior Service Cost (Credit)		(36.6)	(41.6)
Components of Change in Amounts Included in AOCI and Regulatory Assets
Actuarial (Gain) Loss During the Year		4	12
Amortization of Actuarial Gain (Loss)		(1.9)	(1.1)
Amortization of Prior Service Credit (Cost)		5	5.2
Change for the Year		7.1	16.1
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Regulatory Assets [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		5.7	1.2
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Deferred Income Taxes [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		1.1	0.2
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Net of Tax AOCI [Member]
Recorded as
Total of Amounts Included in AOCI and Regulatory Assets		$ 2	$ 0.3
[1]	Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.
[2]	Rates are for base pay only. In addition, an amount is added to reflect target incentive compensation for exempt employees and overtime and incentive pay for nonexempt employees.

Benefit Plans 2 (Details)

Benefit Plans 2 (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2013	Dec. 31, 2014
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	$ 13.3		$ 28.7		$ (7.6)
Transfers out of Level 3	[2]	(2.6)		(18.9)		(21.5)
Appalachian Power Co [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0	[3]	0	[3]	(3.6)
Transfers out of Level 3	[2]	0.1	[3]	1.2	[3]	0
Indiana Michigan Power Co [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0	[3]	0	[3]	(2.5)
Transfers out of Level 3	[2]	0.1	[3]	0.8	[3]	0
Ohio Power Co [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0		0		0
Transfers out of Level 3	[2]	0		0		0
Public Service Co Of Oklahoma [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0		0		0
Transfers out of Level 3	[2]	0		0		0
Southwestern Electric Power Co [Member]
Actual Return on Plan Assets
Transfers into Level 3	[1],[2]	0		0		0
Transfers out of Level 3	[2]	0		0		$ 0
Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 4,827.3		$ 4,767.6			$ 4,967.5
Year End Allocation
Total		100.00%		100.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 4,827.3		$ 4,767.6			4,967.5
Actual Return on Plan Assets
Balance as of December 31		$ 4,827.3		$ 4,767.6			4,967.5
Pension Plan [Member] | Appalachian Power Co [Member]
Allocated Assets of Investments		12.60%		12.70%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 606.4		$ 603.2			642.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		606.4		603.2			642.3
Actual Return on Plan Assets
Balance as of December 31		$ 606.4		$ 603.2			642.3
Pension Plan [Member] | Indiana Michigan Power Co [Member]
Allocated Assets of Investments		12.10%		12.00%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 586.1		$ 570			591.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		586.1		570			591.7
Actual Return on Plan Assets
Balance as of December 31		$ 586.1		$ 570			591.7
Pension Plan [Member] | Ohio Power Co [Member]
Allocated Assets of Investments		9.80%		9.90%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 473.8		$ 472.1			498.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		473.8		472.1			498.5
Actual Return on Plan Assets
Balance as of December 31		$ 473.8		$ 472.1			498.5
Pension Plan [Member] | Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments		5.50%		5.50%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 266		$ 262.1			275.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		266		262.1			275.5
Actual Return on Plan Assets
Balance as of December 31		$ 266		$ 262.1			275.5
Pension Plan [Member] | Southwestern Electric Power Co [Member]
Allocated Assets of Investments		6.00%		5.90%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 287.3		$ 280.6			290.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		287.3		280.6			290.2
Actual Return on Plan Assets
Balance as of December 31		287.3		280.6			290.2
Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 1,545.9		$ 1,577.4			1,693.9
Year End Allocation
Total		100.00%		100.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 1,545.9		$ 1,577.4			1,693.9
Actual Return on Plan Assets
Balance as of December 31		$ 1,545.9		$ 1,577.4			1,693.9
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Allocated Assets of Investments		16.00%		16.30%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 246.9		$ 256.7			280.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		246.9		256.7			280.6
Actual Return on Plan Assets
Balance as of December 31		$ 246.9		$ 256.7			280.6
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Allocated Assets of Investments		12.10%		12.00%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 186.6		$ 189			202.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		186.6		189			202.4
Actual Return on Plan Assets
Balance as of December 31		$ 186.6		$ 189			202.4
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Allocated Assets of Investments		11.80%		12.10%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 182.6		$ 191.6			206.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		182.6		191.6			206.2
Actual Return on Plan Assets
Balance as of December 31		$ 182.6		$ 191.6			206.2
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Allocated Assets of Investments		5.60%		5.60%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 86.4		$ 88.3			96
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		86.4		88.3			96
Actual Return on Plan Assets
Balance as of December 31		$ 86.4		$ 88.3			96
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Allocated Assets of Investments		6.30%		6.20%
Pension and Other Postretirement Plans' Assets
Asset Class		$ 96.8		$ 97.8			106.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		96.8		97.8			106.4
Actual Return on Plan Assets
Balance as of December 31		96.8		97.8			106.4
Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		365		279.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		365		279.2
Actual Return on Plan Assets
Balance as of December 31		365		279.2
Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		318.9		338.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		318.9		338.3
Actual Return on Plan Assets
Balance as of December 31		318.9		338.3
Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		797		722
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		797		722
Actual Return on Plan Assets
Balance as of December 31		797		722
Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		976.6		994.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		976.6		994.3
Actual Return on Plan Assets
Balance as of December 31		976.6		994.3
Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		2,941.7		3,091.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		2,941.7		3,091.9
Actual Return on Plan Assets
Balance as of December 31		2,941.7		3,091.9
Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		250.4		244.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		250.4		244.8
Actual Return on Plan Assets
Balance as of December 31		250.4		244.8
Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		723.6		674.5			627.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		723.6		674.5			627.3
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		24.9		(17)
Relating to Assets Sold During the Period		45.2		61.7
Purchases and Sales		(21)		2.5
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		723.6		674.5			627.3
Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Equity Securities [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 1,231.5		$ 1,123.4
Year End Allocation
Total		25.50%		23.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 1,231.5		$ 1,123.4
Actual Return on Plan Assets
Balance as of December 31		1,231.5		1,123.4
Equity Securities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 999.2		$ 996.6
Year End Allocation
Total		64.70%		63.20%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 999.2		$ 996.6
Actual Return on Plan Assets
Balance as of December 31		999.2		996.6
Equity Securities [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		400.5		369.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		400.5		369.7
Actual Return on Plan Assets
Balance as of December 31		400.5		369.7
Equity Securities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		20.5		19
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		20.5		19
Actual Return on Plan Assets
Balance as of December 31		20.5		19
Equity Securities [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		797		722
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		797		722
Actual Return on Plan Assets
Balance as of December 31		797		722
Equity Securities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		952.6		949.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		952.6		949.4
Actual Return on Plan Assets
Balance as of December 31		952.6		949.4
Equity Securities [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		34		31.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		34		31.7
Actual Return on Plan Assets
Balance as of December 31		34		31.7
Equity Securities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		26.1		28.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		26.1		28.2
Actual Return on Plan Assets
Balance as of December 31		26.1		28.2
Equity Securities [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Equity Securities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 354.7		$ 315.7
Year End Allocation
Total		7.30%		6.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 354.7		$ 315.7
Actual Return on Plan Assets
Balance as of December 31		354.7		315.7
Domestic [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 517.1		$ 465.1
Year End Allocation
Total		33.50%		29.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 517.1		$ 465.1
Actual Return on Plan Assets
Balance as of December 31		517.1		465.1
Domestic [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		354.7		315.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		354.7		315.7
Actual Return on Plan Assets
Balance as of December 31		354.7		315.7
Domestic [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		517.1		465.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		517.1		465.1
Actual Return on Plan Assets
Balance as of December 31		517.1		465.1
Domestic [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Domestic [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 439.2		$ 402.3
Year End Allocation
Total		9.10%		8.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 439.2		$ 402.3
Actual Return on Plan Assets
Balance as of December 31		439.2		402.3
International [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 435.5		$ 484.3
Year End Allocation
Total		28.20%		30.70%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 435.5		$ 484.3
Actual Return on Plan Assets
Balance as of December 31		435.5		484.3
International [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		439.2		402.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		439.2		402.3
Actual Return on Plan Assets
Balance as of December 31		439.2		402.3
International [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		435.5		484.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		435.5		484.3
Actual Return on Plan Assets
Balance as of December 31		435.5		484.3
International [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 20		$ 15.6
Year End Allocation
Total		0.40%		0.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 20		$ 15.6
Actual Return on Plan Assets
Balance as of December 31		20		15.6
Options [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 15.2		$ 15.6
Year End Allocation
Total		1.00%		1.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 15.2		$ 15.6
Actual Return on Plan Assets
Balance as of December 31		15.2		15.6
Options [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		20		15.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		20		15.6
Actual Return on Plan Assets
Balance as of December 31		20		15.6
Options [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		15.2		15.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		15.2		15.6
Actual Return on Plan Assets
Balance as of December 31		15.2		15.6
Options [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Options [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate Investment Trusts [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 3.1		$ 4
Year End Allocation
Total		0.10%		0.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 3.1		$ 4
Actual Return on Plan Assets
Balance as of December 31		3.1		4
Real Estate Investment Trusts [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate Investment Trusts [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		3.1		4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		3.1		4
Actual Return on Plan Assets
Balance as of December 31		3.1		4
Real Estate Investment Trusts [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate Investment Trusts [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trusts [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 414.5		$ 385.8
Year End Allocation
Total	[4]	8.60%		8.10%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	$ 414.5		$ 385.8
Actual Return on Plan Assets
Balance as of December 31	[4]	414.5		385.8
Common Collective Trusts [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	$ 31.4		$ 31.6
Year End Allocation
Total	[5]	2.00%		2.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	$ 31.4		$ 31.6
Actual Return on Plan Assets
Balance as of December 31	[5]	31.4		31.6
Common Collective Trusts [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	400.5		369.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	400.5		369.7
Actual Return on Plan Assets
Balance as of December 31	[4]	400.5		369.7
Common Collective Trusts [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	20.5		19
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	20.5		19
Actual Return on Plan Assets
Balance as of December 31	[5]	20.5		19
Common Collective Trusts [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Common Collective Trusts [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
Common Collective Trusts [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	14		16.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	14		16.1
Actual Return on Plan Assets
Balance as of December 31	[4]	14		16.1
Common Collective Trusts [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	10.9		12.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	10.9		12.6
Actual Return on Plan Assets
Balance as of December 31	[5]	10.9		12.6
Common Collective Trusts [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Common Collective Trusts [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
Fixed Income [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 2,825.6		$ 2,897
Year End Allocation
Total		58.50%		60.80%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 2,825.6		$ 2,897
Actual Return on Plan Assets
Balance as of December 31		2,825.6		2,897
Fixed Income [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 307.5		$ 310.3
Year End Allocation
Total		19.90%		19.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 307.5		$ 310.3
Actual Return on Plan Assets
Balance as of December 31		307.5		310.3
Fixed Income [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		79.5		100.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		79.5		100.9
Actual Return on Plan Assets
Balance as of December 31		79.5		100.9
Fixed Income [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		93.7		100.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		93.7		100.9
Actual Return on Plan Assets
Balance as of December 31		93.7		100.9
Fixed Income [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Fixed Income [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Fixed Income [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		2,746.1		2,796
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		2,746.1		2,796
Actual Return on Plan Assets
Balance as of December 31		2,746.1		2,796
Fixed Income [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		213.8		209.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		213.8		209.4
Actual Return on Plan Assets
Balance as of December 31		213.8		209.4
Fixed Income [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0.1
Actual Return on Plan Assets
Balance as of December 31		0		0.1
Fixed Income [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Common Collective Trust - Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 32.3		$ 34.2
Year End Allocation
Total	[4]	0.70%		0.70%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	$ 32.3		$ 34.2
Actual Return on Plan Assets
Balance as of December 31	[4]	32.3		34.2
Common Collective Trust - Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	$ 93.7		$ 100.9
Year End Allocation
Total	[5]	6.00%		6.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	$ 93.7		$ 100.9
Actual Return on Plan Assets
Balance as of December 31	[5]	93.7		100.9
Common Collective Trust - Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	32.3		34.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	32.3		34.2
Actual Return on Plan Assets
Balance as of December 31	[4]	32.3		34.2
Common Collective Trust - Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	93.7		100.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	93.7		100.9
Actual Return on Plan Assets
Balance as of December 31	[5]	93.7		100.9
Common Collective Trust - Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Common Collective Trust - Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
Common Collective Trust - Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Common Collective Trust - Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
Common Collective Trust - Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Common Collective Trust - Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
United States Government and Agency Securities [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 441		$ 421.9
Year End Allocation
Total	[4]	9.10%		8.90%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	$ 441		$ 421.9
Actual Return on Plan Assets
Balance as of December 31	[4]	441		421.9
United States Government and Agency Securities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 64.7		$ 58.4
Year End Allocation
Total		4.20%		3.70%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 64.7		$ 58.4
Actual Return on Plan Assets
Balance as of December 31		64.7		58.4
United States Government and Agency Securities [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	17.7		24.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	17.7		24.1
Actual Return on Plan Assets
Balance as of December 31	[4]	17.7		24.1
United States Government and Agency Securities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Government and Agency Securities [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
United States Government and Agency Securities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
United States Government and Agency Securities [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	423.3		397.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	423.3		397.8
Actual Return on Plan Assets
Balance as of December 31	[4]	423.3		397.8
United States Government and Agency Securities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		64.7		58.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		64.7		58.4
Actual Return on Plan Assets
Balance as of December 31		64.7		58.4
United States Government and Agency Securities [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
United States Government and Agency Securities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 1,942.2		$ 1,983.2
Year End Allocation
Total	[4]	40.20%		41.60%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	$ 1,942.2		$ 1,983.2
Actual Return on Plan Assets
Balance as of December 31	[4]	1,942.2		1,983.2
Corporate Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 121.6		$ 117.7
Year End Allocation
Total		7.90%		7.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 121.6		$ 117.7
Actual Return on Plan Assets
Balance as of December 31		121.6		117.7
Corporate Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	10		19
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	10		19
Actual Return on Plan Assets
Balance as of December 31	[4]	10		19
Corporate Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Corporate Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Corporate Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	1,932.2		1,964.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	1,932.2		1,964.2
Actual Return on Plan Assets
Balance as of December 31	[4]	1,932.2		1,964.2
Corporate Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		121.6		117.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		121.6		117.7
Actual Return on Plan Assets
Balance as of December 31		121.6		117.7
Corporate Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Corporate Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Foreign Debt [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 385.8		$ 421.5
Year End Allocation
Total	[4]	8.00%		8.80%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	$ 385.8		$ 421.5
Actual Return on Plan Assets
Balance as of December 31	[4]	385.8		421.5
Foreign Debt [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 18.6		$ 20.7
Year End Allocation
Total		1.20%		1.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 18.6		$ 20.7
Actual Return on Plan Assets
Balance as of December 31		18.6		20.7
Foreign Debt [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	12.1		16
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	12.1		16
Actual Return on Plan Assets
Balance as of December 31	[4]	12.1		16
Foreign Debt [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Foreign Debt [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Foreign Debt [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Foreign Debt [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	373.7		405.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	373.7		405.4
Actual Return on Plan Assets
Balance as of December 31	[4]	373.7		405.4
Foreign Debt [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		18.6		20.7
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		18.6		20.7
Actual Return on Plan Assets
Balance as of December 31		18.6		20.7
Foreign Debt [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0	[4]	0.1	[4]		0.1
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0	[4]	0.1	[4]		0.1
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		0		0
Relating to Assets Sold During the Period		0		0
Purchases and Sales		(0.1)		0
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		0	[4]	0.1	[4]		0.1
Foreign Debt [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 11.5		$ 12.8
Year End Allocation
Total		0.20%		0.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 11.5		$ 12.8
Actual Return on Plan Assets
Balance as of December 31		11.5		12.8
State and Local Government [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 3		$ 4.2
Year End Allocation
Total		0.20%		0.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 3		$ 4.2
Actual Return on Plan Assets
Balance as of December 31		3		4.2
State and Local Government [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		11.5		12.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		11.5		12.8
Actual Return on Plan Assets
Balance as of December 31		11.5		12.8
State and Local Government [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		3		4.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		3		4.2
Actual Return on Plan Assets
Balance as of December 31		3		4.2
State and Local Government [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
State and Local Government [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 12.8		$ 23.4
Year End Allocation
Total	[4]	0.30%		0.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	$ 12.8		$ 23.4
Actual Return on Plan Assets
Balance as of December 31	[4]	12.8		23.4
Other - Asset Backed [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 5.9		$ 8.4
Year End Allocation
Total		0.40%		0.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 5.9		$ 8.4
Actual Return on Plan Assets
Balance as of December 31		5.9		8.4
Other - Asset Backed [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	7.4		7.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	7.4		7.6
Actual Return on Plan Assets
Balance as of December 31	[4]	7.4		7.6
Other - Asset Backed [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Other - Asset Backed [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Asset Backed [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	5.4		15.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	5.4		15.8
Actual Return on Plan Assets
Balance as of December 31	[4]	5.4		15.8
Other - Asset Backed [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		5.9		8.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		5.9		8.4
Actual Return on Plan Assets
Balance as of December 31		5.9		8.4
Other - Asset Backed [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Other - Asset Backed [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Infrastructure [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 57.6		$ 42
Year End Allocation
Total		1.20%		0.90%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 57.6		$ 42
Actual Return on Plan Assets
Balance as of December 31		57.6		42
Infrastructure [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Infrastructure [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Infrastructure [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Infrastructure [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		57.6		42			12.5
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		57.6		42			12.5
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		5.9		(3.6)
Relating to Assets Sold During the Period		0.9		0.3
Purchases and Sales		8.8		32.8
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		57.6		42			12.5
Real Estate [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 254.9		$ 253.7
Year End Allocation
Total		5.30%		5.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 254.9		$ 253.7
Actual Return on Plan Assets
Balance as of December 31		254.9		253.7
Real Estate [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Real Estate [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		254.9		253.7			235.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		254.9		253.7			235.8
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		5.3		12.5
Relating to Assets Sold During the Period		23.2		23.8
Purchases and Sales		(27.3)		(18.4)
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		254.9		253.7			235.8
Alternative Investments [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 411.1		$ 378.7
Year End Allocation
Total		8.50%		8.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 411.1		$ 378.7
Actual Return on Plan Assets
Balance as of December 31		411.1		378.7
Alternative Investments [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Alternative Investments [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Alternative Investments [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Alternative Investments [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		411.1		378.7			378.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		411.1		378.7			378.9
Actual Return on Plan Assets
Relating to Assets Still Held as of the Reporting Date		13.7		(25.9)
Relating to Assets Sold During the Period		21.1		37.6
Purchases and Sales		(2.4)		(11.9)
Transfers into Level 3		0		0
Transfers out of Level 3		0		0
Balance as of December 31		411.1		378.7			$ 378.9
Securities Lending [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 161.6		$ 263
Year End Allocation
Total		3.40%		5.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 161.6		$ 263
Actual Return on Plan Assets
Balance as of December 31		161.6		263
Securities Lending [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Securities Lending [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Securities Lending [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		161.6		263
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		161.6		263
Actual Return on Plan Assets
Balance as of December 31		161.6		263
Securities Lending [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Securities Lending Collateral [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	$ (163.3)		$ (264.7)
Year End Allocation
Total	[6]	(3.40%)		(5.50%)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	$ (163.3)		$ (264.7)
Actual Return on Plan Assets
Balance as of December 31	[6]	(163.3)		(264.7)
Securities Lending Collateral [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	(163.3)		(264.7)
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	(163.3)		(264.7)
Actual Return on Plan Assets
Balance as of December 31	[6]	(163.3)		(264.7)
Securities Lending Collateral [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	0		0
Actual Return on Plan Assets
Balance as of December 31	[6]	0		0
Securities Lending Collateral [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	0		0
Actual Return on Plan Assets
Balance as of December 31	[6]	0		0
Securities Lending Collateral [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[6]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[6]	0		0
Actual Return on Plan Assets
Balance as of December 31	[6]	0		0
Trusted Owned Life Insurance [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 207.5		$ 212.6
Year End Allocation
Total		13.40%		13.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 207.5		$ 212.6
Actual Return on Plan Assets
Balance as of December 31		207.5		212.6
Trusted Owned Life Insurance [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		207.5		212.6
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		207.5		212.6
Actual Return on Plan Assets
Balance as of December 31		207.5		212.6
Trusted Owned Life Insurance [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Trusted Owned Life Insurance [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Trusted Owned Life Insurance [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
International Equities [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	$ 110.1		$ 28.3
Year End Allocation
Total	[5]	7.10%		1.80%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	$ 110.1		$ 28.3
Actual Return on Plan Assets
Balance as of December 31	[5]	110.1		28.3
International Equities [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	110.1		28.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	110.1		28.3
Actual Return on Plan Assets
Balance as of December 31	[5]	110.1		28.3
International Equities [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
International Equities [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
International Equities [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
United States Bonds [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	$ 97.4		$ 184.3
Year End Allocation
Total	[5]	6.30%		11.70%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	$ 97.4		$ 184.3
Actual Return on Plan Assets
Balance as of December 31	[5]	97.4		184.3
United States Bonds [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	97.4		184.3
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	97.4		184.3
Actual Return on Plan Assets
Balance as of December 31	[5]	97.4		184.3
United States Bonds [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
United States Bonds [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
United States Bonds [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[5]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[5]	0		0
Actual Return on Plan Assets
Balance as of December 31	[5]	0		0
Cash and Cash Equivalents [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	$ 29.7		$ 48.6
Year End Allocation
Total	[4]	0.60%		1.00%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	$ 29.7		$ 48.6
Actual Return on Plan Assets
Balance as of December 31	[4]	29.7		48.6
Cash and Cash Equivalents [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		$ 34.5		$ 52.1
Year End Allocation
Total		2.20%		3.30%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		$ 34.5		$ 52.1
Actual Return on Plan Assets
Balance as of December 31		34.5		52.1
Cash and Cash Equivalents [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	29.7		47.4
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	29.7		47.4
Actual Return on Plan Assets
Balance as of December 31	[4]	29.7		47.4
Cash and Cash Equivalents [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Cash and Cash Equivalents [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Cash and Cash Equivalents [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		24		44.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		24		44.9
Actual Return on Plan Assets
Balance as of December 31		24		44.9
Cash and Cash Equivalents [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		1.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		1.2
Actual Return on Plan Assets
Balance as of December 31	[4]	0		1.2
Cash and Cash Equivalents [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		10.5		7.2
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		10.5		7.2
Actual Return on Plan Assets
Balance as of December 31		10.5		7.2
Cash and Cash Equivalents [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[4]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[4]	0		0
Actual Return on Plan Assets
Balance as of December 31	[4]	0		0
Cash and Cash Equivalents [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class		0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1		0		0
Actual Return on Plan Assets
Balance as of December 31		0		0
Other - Pending Transactions and Accrued Income [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	$ 18.6		$ 25.9
Year End Allocation
Total	[7]	0.40%		0.50%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	$ 18.6		$ 25.9
Actual Return on Plan Assets
Balance as of December 31	[7]	18.6		25.9
Other - Pending Transactions and Accrued Income [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[8]	$ (2.8)		$ 5.8
Year End Allocation
Total	[8]	(0.20%)		0.40%
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[8]	$ (2.8)		$ 5.8
Actual Return on Plan Assets
Balance as of December 31	[8]	(2.8)		5.8
Other - Pending Transactions and Accrued Income [Member] | Other [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	18.6		25.9
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	18.6		25.9
Actual Return on Plan Assets
Balance as of December 31	[7]	18.6		25.9
Other - Pending Transactions and Accrued Income [Member] | Other [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[8]	(2.8)		5.8
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[8]	(2.8)		5.8
Actual Return on Plan Assets
Balance as of December 31	[8]	(2.8)		5.8
Other - Pending Transactions and Accrued Income [Member] | Level 1 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	0		0
Actual Return on Plan Assets
Balance as of December 31	[7]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 1 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[8]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[8]	0		0
Actual Return on Plan Assets
Balance as of December 31	[8]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 2 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	0		0
Actual Return on Plan Assets
Balance as of December 31	[7]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 2 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[8]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[8]	0		0
Actual Return on Plan Assets
Balance as of December 31	[8]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 3 [Member] | Pension Plan [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[7]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[7]	0		0
Actual Return on Plan Assets
Balance as of December 31	[7]	0		0
Other - Pending Transactions and Accrued Income [Member] | Level 3 [Member] | Other Postretirement Benefit Plans [Member]
Pension and Other Postretirement Plans' Assets
Asset Class	[8]	0		0
Reconciliation of Changes in Fair Value of Assets Classified as Level 3 in Fair Value Hierarchy for the Pension Assets
Balance as of January 1	[8]	0		0
Actual Return on Plan Assets
Balance as of December 31	[8]	$ 0		$ 0
[1]	Represents existing assets or liabilities that were previously categorized as Level 2.
[2]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[3]	Includes both affiliated and nonaffiliated transactions.
[4]	Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods.
[5]	Amounts in “Other” column represent investments for which fair value is measured using net asset value per share in accordance with ASU 2015-07, Disclosure for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent), which was retrospectively applied to prior periods.
[6]	Amounts in “Other” column primarily represent an obligation to repay collateral received as part of the Securities Lending Program.
[7]	Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.
[8]	Amounts in “Other” column primarily represent accrued interest, dividend receivables and transactions pending settlement.

Benefit Plans 3 (Details)

Benefit Plans 3 (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 72.9	$ 73.6	$ 70.5
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Multiemployer Plan Surcharge		10.00%	5.00%
Multiemployer Plans Withdrawal Obligation	$ 39	$ 31
Noncurrent Regulatory Assets	5,625.5	5,140.3
UMWA Withdrawal Obligation [Member]
Benefit Plans Textuals [Abstract]
Noncurrent Regulatory Assets	20	14
Appalachian Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 7.3	$ 7.2	$ 7.3
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Multiemployer Plan Surcharge	10.00%	5.00%
Noncurrent Regulatory Assets	$ 1,121.1	$ 1,154.2
Indiana Michigan Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 10.9	10.6	10.5
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 916.6	804.3
Ohio Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 5.6	5.4	5.2
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 1,107.5	1,113
Public Service Co Of Oklahoma [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 4.3	4.2	4
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 340.2	214.8
Southwestern Electric Power Co [Member]
American Electric Power System Retirement Savings Plans
Cost of Company Matching Contributions	$ 5.7	5.7	5.3
Benefit Plans Textuals [Abstract]
Matching Contributions Provided Percentage	100.00%
Eligible Compensation Contribution by Employee Percentage	1.00%
Second Matching Contributions Provided Percentage	70.00%
Second Eligible Compensation Contribution by Employee Percentage	5.00%
Noncurrent Regulatory Assets	$ 551.2	415.8
Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,915.8	4,832.7
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	5,085.8	4,992.9	5,224.9
Accumulated Benefit Obligation	4,915.8	4,832.7
Fair Value of Plan Assets	4,827.3	4,767.6	4,967.5
Underfunded Status, Accumulated Benefit Obligation	(88.5)	(65.1)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	98.2
Components of Net Periodic Benefit Cost
Service Cost	85.8	93.5	71.9
Interest Cost	211.6	205.3	221
Expected Return on Plan Assets	(280.3)	(274.8)	(261.6)
Amortization of Prior Service Cost (Credit)	2.3	2.2	2.5
Amortization of Net Actuarial Loss	83.8	107.1	124
Net Periodic Benefit Cost (Credit)	103.2	133.3	157.8
Capitalized Portion	(37.8)	(48.4)	(52.2)
Net Periodic Benefit Cost (Credit) Recognized in Expense	65.4	84.9	105.6
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	84.2
Prior Service Cost (Credit)	1
Total Estimated 2017 Amortization	85.2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	85.2
Pension Plans [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	332.6
2,018	335.6
2,019	344.5
2,020	351.2
2,021	364.4
Years 2022 to 2026, in Total	1,841.2
Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	641.3	641.9
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	654	653.4	702.8
Accumulated Benefit Obligation	641.3	641.9
Fair Value of Plan Assets	606.4	603.2	642.3
Underfunded Status, Accumulated Benefit Obligation	(34.9)	(38.7)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	10.2
Components of Net Periodic Benefit Cost
Service Cost	8.1	8.7	7
Interest Cost	27.2	26.7	29.6
Expected Return on Plan Assets	(35.3)	(35)	(33.9)
Amortization of Prior Service Cost (Credit)	0.1	0.2	0.2
Amortization of Net Actuarial Loss	10.8	13.9	16.6
Net Periodic Benefit Cost (Credit)	10.9	14.5	19.5
Capitalized Portion	(4.1)	(5.5)	(6.8)
Net Periodic Benefit Cost (Credit) Recognized in Expense	6.8	9	12.7
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	10.7
Prior Service Cost (Credit)	0.2
Total Estimated 2017 Amortization	10.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	10.9
Pension Plans [Member] | Appalachian Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	43.2
2,018	42.9
2,019	43.8
2,020	44.5
2,021	46
Years 2022 to 2026, in Total	231.2
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	588.8	571.7
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	611.6	591.5	617.9
Accumulated Benefit Obligation	588.8	571.7
Fair Value of Plan Assets	586.1	570	591.7
Underfunded Status, Accumulated Benefit Obligation	(2.7)	(1.7)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	13.6
Components of Net Periodic Benefit Cost
Service Cost	12.2	12.9	10
Interest Cost	25.3	24.5	26.3
Expected Return on Plan Assets	(33.6)	(32.6)	(31)
Amortization of Prior Service Cost (Credit)	0.1	0.2	0.2
Amortization of Net Actuarial Loss	10	12.6	14.6
Net Periodic Benefit Cost (Credit)	14	17.6	20.1
Capitalized Portion	(3.3)	(4)	(4.6)
Net Periodic Benefit Cost (Credit) Recognized in Expense	10.7	13.6	15.5
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	10
Prior Service Cost (Credit)	0.2
Total Estimated 2017 Amortization	10.2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	10.2
Pension Plans [Member] | Indiana Michigan Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	35.7
2,018	35.9
2,019	38.6
2,020	38.7
2,021	40.2
Years 2022 to 2026, in Total	216.5
Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	478	484.2
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	492.9	497.5	526.3
Accumulated Benefit Obligation	478	484.2
Fair Value of Plan Assets	473.8	472.1	498.5
Underfunded Status, Accumulated Benefit Obligation	(4.2)	(12.1)
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	7.6
Components of Net Periodic Benefit Cost
Service Cost	6.5	6.7	5.2
Interest Cost	20.6	20.3	22.1
Expected Return on Plan Assets	(27.6)	(27.5)	(26.5)
Amortization of Prior Service Cost (Credit)	0.1	0.2	0.2
Amortization of Net Actuarial Loss	8.1	10.5	12.4
Net Periodic Benefit Cost (Credit)	7.7	10.2	13.4
Capitalized Portion	(3.4)	(4.8)	(5.5)
Net Periodic Benefit Cost (Credit) Recognized in Expense	4.3	5.4	7.9
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	8.1
Prior Service Cost (Credit)	0.1
Total Estimated 2017 Amortization	8.2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	8.2
Pension Plans [Member] | Ohio Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	35.8
2,018	35.7
2,019	35.8
2,020	36.1
2,021	35.4
Years 2022 to 2026, in Total	172.6
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	254.2	254.4
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	266.7	265.4	285.4
Accumulated Benefit Obligation	254.2	254.4
Fair Value of Plan Assets	266	262.1	275.5
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	5.5
Components of Net Periodic Benefit Cost
Service Cost	6.2	6.4	5.2
Interest Cost	11.2	10.9	12.1
Expected Return on Plan Assets	(15.5)	(15.1)	(14.6)
Amortization of Prior Service Cost (Credit)	0.3	0.2	0.3
Amortization of Net Actuarial Loss	4.4	5.7	6.7
Net Periodic Benefit Cost (Credit)	6.6	8.1	9.7
Capitalized Portion	(2.4)	(2.8)	(3.3)
Net Periodic Benefit Cost (Credit) Recognized in Expense	4.2	5.3	6.4
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	4.4
Prior Service Cost (Credit)	0
Total Estimated 2017 Amortization	4.4
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	4.4
Pension Plans [Member] | Public Service Co Of Oklahoma [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	19.6
2,018	19.3
2,019	20.3
2,020	20.4
2,021	21.9
Years 2022 to 2026, in Total	106.7
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	281.5	269.3
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	296.6	282.8	298.2
Accumulated Benefit Obligation	281.5	269.3
Fair Value of Plan Assets	287.3	280.6	290.2
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	8.7
Components of Net Periodic Benefit Cost
Service Cost	8.1	8.3	6.6
Interest Cost	12.4	11.8	12.7
Expected Return on Plan Assets	(16.4)	(16)	(15.4)
Amortization of Prior Service Cost (Credit)	0.3	0.3	0.3
Amortization of Net Actuarial Loss	4.8	6	7.1
Net Periodic Benefit Cost (Credit)	9.2	10.4	11.3
Capitalized Portion	(2.7)	(3.2)	(3.4)
Net Periodic Benefit Cost (Credit) Recognized in Expense	6.5	7.2	7.9
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	4.9
Prior Service Cost (Credit)	0
Total Estimated 2017 Amortization	4.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	4.9
Pension Plans [Member] | Southwestern Electric Power Co [Member] | Pension Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	20.1
2,018	21.3
2,019	22
2,020	22.6
2,021	23.6
Years 2022 to 2026, in Total	122.2
Qualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,846	4,757.1
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	4,846	4,757.1
Qualified Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	641	641.4
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	641	641.4
Qualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	588.5	571.3
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	588.5	571.3
Qualified Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	478	484.1
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	478	484.1
Qualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	252	252
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	252	252
Qualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	279.8	267.7
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	279.8	267.7
Nonqualified Pension Plans [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	69.8	75.6
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	69.8	75.6
Nonqualified Pension Plans [Member] | Appalachian Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.3	0.5
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.3	0.5
Nonqualified Pension Plans [Member] | Indiana Michigan Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.3	0.4
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	0.3	0.4
Nonqualified Pension Plans [Member] | Ohio Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	0	0.1
Underfunded Accumulated Benefit Obligation
Accumulated Benefit Obligation	0	0.1
Nonqualified Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	2.2	2.4
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	2.3	2.6
Accumulated Benefit Obligation	2.2	2.4
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(2.2)	(2.4)
Nonqualified Pension Plans [Member] | Southwestern Electric Power Co [Member]
Accumulated Benefit Obligation
Accumulated Benefit Obligation	1.7	1.6
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	1.7	1.7
Accumulated Benefit Obligation	1.7	1.6
Fair Value of Plan Assets	0	0
Underfunded Status, Accumulated Benefit Obligation	(1.7)	(1.6)
Other Postretirement Benefit Plans [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	1,447.4	1,450.6	1,439
Fair Value of Plan Assets	1,545.9	1,577.4	1,693.9
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	4.3
Components of Net Periodic Benefit Cost
Service Cost	10.2	12.2	14.2
Interest Cost	60.9	56.8	67.2
Expected Return on Plan Assets	(107)	(111)	(111.3)
Amortization of Prior Service Cost (Credit)	(69)	(69.1)	(69)
Amortization of Net Actuarial Loss	31.4	18.8	22.1
Net Periodic Benefit Cost (Credit)	(73.5)	(92.3)	(76.8)
Capitalized Portion	26.9	33.5	25.3
Net Periodic Benefit Cost (Credit) Recognized in Expense	(46.6)	(58.8)	(51.5)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	34.4
Prior Service Cost (Credit)	(69)
Total Estimated 2017 Amortization	(34.6)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(34.6)
Other Postretirement Benefit Plans [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	137
2,018	138.2
2,019	138.3
2,020	139.7
2,021	141.1
Years 2022 to 2026, in Total	718
Other Postretirement Benefit Plans [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,017	0.3
2,018	0.3
2,019	0.3
2,020	0.3
2,021	0.3
Years 2022 to 2026, in Total	1.7
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	255.6	262.2	267.1
Fair Value of Plan Assets	246.9	256.7	280.6
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	2.4
Components of Net Periodic Benefit Cost
Service Cost	1	1.1	1.4
Interest Cost	10.8	10.3	12.8
Expected Return on Plan Assets	(17.3)	(18.1)	(18.5)
Amortization of Prior Service Cost (Credit)	(10.1)	(10)	(10.1)
Amortization of Net Actuarial Loss	5.4	3.6	4.6
Net Periodic Benefit Cost (Credit)	(10.2)	(13.1)	(9.8)
Capitalized Portion	3.9	5	3.4
Net Periodic Benefit Cost (Credit) Recognized in Expense	(6.3)	(8.1)	(6.4)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	5.8
Prior Service Cost (Credit)	(10)
Total Estimated 2017 Amortization	(4.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(4.2)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	25.4
2,018	25.6
2,019	25.2
2,020	25.2
2,021	25.1
Years 2022 to 2026, in Total	122.7
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,017	0.2
2,018	0.2
2,019	0.2
2,020	0.2
2,021	0.2
Years 2022 to 2026, in Total	1
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	167.6	166.3	161.7
Fair Value of Plan Assets	186.6	189	202.4
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	0
Components of Net Periodic Benefit Cost
Service Cost	1.5	1.6	1.9
Interest Cost	7	6.4	7.6
Expected Return on Plan Assets	(12.9)	(13.2)	(13.4)
Amortization of Prior Service Cost (Credit)	(9.4)	(9.4)	(9.4)
Amortization of Net Actuarial Loss	3.7	2	2.4
Net Periodic Benefit Cost (Credit)	(10.1)	(12.6)	(10.9)
Capitalized Portion	2.4	2.9	2.5
Net Periodic Benefit Cost (Credit) Recognized in Expense	(7.7)	(9.7)	(8.4)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	4.1
Prior Service Cost (Credit)	(9.4)
Total Estimated 2017 Amortization	(5.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(5.3)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	16.6
2,018	16.7
2,019	16.8
2,020	16.9
2,021	17.2
Years 2022 to 2026, in Total	87.6
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,017	0
2,018	0
2,019	0
2,020	0
2,021	0
Years 2022 to 2026, in Total	0
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	164	168.6	164.7
Fair Value of Plan Assets	182.6	191.6	206.2
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	0
Components of Net Periodic Benefit Cost
Service Cost	0.8	0.9	1
Interest Cost	7	6.4	7.6
Expected Return on Plan Assets	(13)	(13.4)	(13.5)
Amortization of Prior Service Cost (Credit)	(6.9)	(7)	(6.9)
Amortization of Net Actuarial Loss	3.8	2.1	2.4
Net Periodic Benefit Cost (Credit)	(8.3)	(11)	(9.4)
Capitalized Portion	3.7	5.2	3.8
Net Periodic Benefit Cost (Credit) Recognized in Expense	(4.6)	(5.8)	(5.6)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	4
Prior Service Cost (Credit)	(6.9)
Total Estimated 2017 Amortization	(2.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(2.9)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	17
2,018	17
2,019	17
2,020	16.9
2,021	16.9
Years 2022 to 2026, in Total	83.8
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,017	0
2,018	0
2,019	0
2,020	0
2,021	0
Years 2022 to 2026, in Total	0
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	77.6	77.7	76.7
Fair Value of Plan Assets	86.4	88.3	96
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	0
Components of Net Periodic Benefit Cost
Service Cost	0.6	0.7	0.8
Interest Cost	3.3	3	3.6
Expected Return on Plan Assets	(6.1)	(6.3)	(6.3)
Amortization of Prior Service Cost (Credit)	(4.3)	(4.3)	(4.3)
Amortization of Net Actuarial Loss	1.8	1	1.1
Net Periodic Benefit Cost (Credit)	(4.7)	(5.9)	(5.1)
Capitalized Portion	1.7	2	1.7
Net Periodic Benefit Cost (Credit) Recognized in Expense	(3)	(3.9)	(3.4)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	1.9
Prior Service Cost (Credit)	(4.3)
Total Estimated 2017 Amortization	(2.4)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(2.4)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	7.6
2,018	7.6
2,019	7.7
2,020	7.9
2,021	7.9
Years 2022 to 2026, in Total	41.1
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,017	0
2,018	0
2,019	0
2,020	0
2,021	0
Years 2022 to 2026, in Total	0
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Underfunded Accumulated Benefit Obligation
Projected Benefit Obligation	86.9	86.1	85
Fair Value of Plan Assets	96.8	97.8	106.4
Estimated Future Benefit Payments and Contributions
Expected Contributions and Payments During 2017	0
Components of Net Periodic Benefit Cost
Service Cost	0.8	0.8	1
Interest Cost	3.6	3.4	4
Expected Return on Plan Assets	(6.8)	(6.9)	(7)
Amortization of Prior Service Cost (Credit)	(5)	(5.2)	(5.2)
Amortization of Net Actuarial Loss	1.9	1.1	1.2
Net Periodic Benefit Cost (Credit)	(5.5)	(6.8)	(6)
Capitalized Portion	1.6	2.1	1.8
Net Periodic Benefit Cost (Credit) Recognized in Expense	(3.9)	$ (4.7)	$ (4.2)
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Net Actuarial Loss	2.2
Prior Service Cost (Credit)	(5.2)
Total Estimated 2017 Amortization	(3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(3)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Benefit Payments [Member]
Estimated Future Benefit Payments and Contributions
2,017	8
2,018	8.1
2,019	8.2
2,020	8.4
2,021	8.7
Years 2022 to 2026, in Total	46.6
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member] | Medicare Subsidy Receipts [Member]
Estimated Future Benefit Payments and Contributions
2,017	0
2,018	0
2,019	0
2,020	0
2,021	0
Years 2022 to 2026, in Total	0
Regulatory Assets [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	74.1
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	74.1
Regulatory Assets [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	10.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	10.9
Regulatory Assets [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	9.6
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	9.6
Regulatory Assets [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	8.2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	8.2
Regulatory Assets [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	4.4
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	4.4
Regulatory Assets [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	4.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	4.9
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(25.1)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(25.1)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(2.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(2.2)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(4.8)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(4.8)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(2.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(2.9)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(2.4)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(2.4)
Regulatory Assets [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(1.9)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(1.9)
Deferred Income Taxes [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	3.9
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	3.9
Deferred Income Taxes [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0.2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0.2
Deferred Income Taxes [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Deferred Income Taxes [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(3.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(3.3)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(0.7)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(0.7)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(0.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(0.2)
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Deferred Income Taxes [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(0.4)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(0.4)
Net of Tax AOCI [Member] | Pension Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	7.2
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	7.2
Net of Tax AOCI [Member] | Pension Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0.4
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0.4
Net of Tax AOCI [Member] | Pension Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Net of Tax AOCI [Member] | Pension Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(6.2)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(6.2)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(1.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(1.3)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(0.3)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	(0.3)
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	0
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	0
Net of Tax AOCI [Member] | Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs
Total Estimated 2017 Amortization	(0.7)
Expected to be Recorded as
Estimated Amounts Expected to be Amortized to Net Periodic Benefit Costs in 2017	$ (0.7)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended												12 Months Ended
		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Reportable Segment Information
Revenues		$ 3,790.1		$ 4,652.2		$ 3,892.9		$ 4,044.9	$ 3,614.7		$ 4,431.4	$ 3,826.7	$ 4,580.4	$ 16,380.1		$ 16,453.2		$ 16,378.6
Asset Impairments and Other Related Charges														2,267.8		0		0
Depreciation and Amortization														1,962.3		2,009.7		1,897.6
Interest and Investment Income														16.3		7.9		7.4
Carrying Costs Income														16.2		23.5		33.2
Interest Expense														877.2		873.9		868
Income Tax Expense (Credit)														(73.7)		919.6		902.6
Income from Continuing Operations		375.2		(764.2)	[1]	506.4		503.1	205.2		511.8	431.4	620.2	620.5		1,768.6		1,590.5
Income from Discontinued Operations, Net of Tax						(2.5)	[2]		265.5	[3]	7.8	(0.1)	10.5	(2.5)		283.7		47.5
NET INCOME (LOSS)		375.2		$ (764.2)	[1]	$ 503.9		$ 503.1	470.7		$ 519.6	$ 431.3	$ 630.7	618		2,052.3		1,638
Gross Property Additions														4,889		4,513.3		4,194.8
Balance Sheet Information
Total Property, Plant and Equipment		62,036.6							65,481.4					62,036.6		65,481.4
Accumulated Depreciation and Amortization		16,397.3							19,348.2					16,397.3		19,348.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		45,639.3	[4]						46,133.2					45,639.3	[4]	46,133.2
Assets Held for Sale		1,951.2												1,951.2
Total Assets		63,467.7							61,683.1					63,467.7		61,683.1		59,544.6
Investments in Equity Method Investees		809.4							720.5					809.4		720.5
Long-term Debt Due Within One Year		2,878							1,831.8					2,878		1,831.8
Long-term Debt - Affiliated		0							0					0		0
Long-term Debt		17,378.4							17,740.9					17,378.4		17,740.9
Total Long-term Debt Outstanding		20,256.4							19,572.7	[5]				20,256.4		19,572.7	[5]
Liabilities Held for Sale		235.9												235.9
Consolidation Eliminations [Member]
Reportable Segment Information
Sales Revenue, Net														0		0		(51.2)	[6]
Revenues														(738.1)		(1,116.5)		(2,056.3)
Asset Impairments and Other Related Charges														0
Depreciation and Amortization	[7]													16.7		15.5		(43.7)
Interest and Investment Income														(16.9)		(15.3)		(19.4)
Carrying Costs Income														(14)		0.1		0
Interest Expense	[7]													(28.4)		(27.2)		(31.7)
Income Tax Expense (Credit)														0		0		0
Income from Continuing Operations														0		0		0
Income from Discontinued Operations, Net of Tax														0		0		0
NET INCOME (LOSS)														0		0		0
Gross Property Additions														(18.1)		(17.8)		(28)
Balance Sheet Information
Total Property, Plant and Equipment	[7]	(353.5)							(279.2)					(353.5)		(279.2)
Accumulated Depreciation and Amortization	[7]	(184)							(112.2)					(184)		(112.2)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[7]	(169.5)							(167)					(169.5)		(167)
Assets Held for Sale		0												0
Total Assets	[7],[8]	(18,888.7)							(19,573)					(18,888.7)		(19,573)		(19,094.2)
Investments in Equity Method Investees		0							0					0		0
Long-term Debt Due Within One Year		0							0					0		0
Long-term Debt - Affiliated		(52.2)							(52.2)					(52.2)		(52.2)
Long-term Debt		0							0					0		0
Total Long-term Debt Outstanding		(52.2)							(52.2)					(52.2)		(52.2)
Liabilities Held for Sale		0												0
Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net														(738.1)		(1,116.5)		(2,005.1)
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales Revenue, Net														9,012.4		9,069.9		9,396.8	[9]
Revenues														9,091.9		9,172.2		9,484.4
Asset Impairments and Other Related Charges														10.5
Depreciation and Amortization														1,073.8		1,062.6		1,033
Interest and Investment Income														4.8		4.6		3.4
Carrying Costs Income														10.5		11.8		6.7
Interest Expense														522.1		517.4		525.5
Income Tax Expense (Credit)														397.3		449.3		433.5
Income from Continuing Operations														984		900.2		711.8
Income from Discontinued Operations, Net of Tax														0		0		0
NET INCOME (LOSS)														984		900.2		711.8
Gross Property Additions														2,237		2,222.3		2,054.7
Balance Sheet Information
Total Property, Plant and Equipment		41,552.6							40,130.3					41,552.6		40,130.3
Accumulated Depreciation and Amortization		12,596.7							12,335					12,596.7		12,335
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		28,955.9							27,795.3					28,955.9		27,795.3
Assets Held for Sale		0												0
Total Assets		37,428.3							35,792.3					37,428.3		35,792.3		33,705.1
Investments in Equity Method Investees		41.2							31.9					41.2		31.9
Long-term Debt Due Within One Year		1,519.9							935.4					1,519.9		935.4
Long-term Debt - Affiliated		20							20					20		20
Long-term Debt		10,353.3							9,833					10,353.3		9,833
Total Long-term Debt Outstanding		11,893.2							10,788.4					11,893.2		10,788.4
Liabilities Held for Sale		0												0
Vertically Integrated Utilities [Member] | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net														79.5		102.3		87.6	[9]
Transmission and Distribution Companies [Member]
Reportable Segment Information
Sales Revenue, Net														4,328.3		4,392		4,552.6
Revenues														4,422.4		4,556.6		4,813.6
Asset Impairments and Other Related Charges														0
Depreciation and Amortization														649.9		686.4		657.8
Interest and Investment Income														14.8		6.4		10.1
Carrying Costs Income														20		11.8		26.5
Interest Expense														256.9		276.2		280.3
Income Tax Expense (Credit)														205.1		185.5		211.7
Income from Continuing Operations														482.1		352.4		352.2
Income from Discontinued Operations, Net of Tax														0		0		0
NET INCOME (LOSS)														482.1		352.4		352.2
Gross Property Additions														1,058.3		1,048.4		1,037.7
Balance Sheet Information
Total Property, Plant and Equipment		14,762.2							13,840.5					14,762.2		13,840.5
Accumulated Depreciation and Amortization		3,655							3,529.2					3,655		3,529.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		11,107.2							10,311.3					11,107.2		10,311.3
Assets Held for Sale		0												0
Total Assets		14,802.4							14,795					14,802.4		14,795		14,524.6
Investments in Equity Method Investees		1.2							0.9					1.2		0.9
Long-term Debt Due Within One Year		309.4							824.7					309.4		824.7
Long-term Debt - Affiliated		0							0					0		0
Long-term Debt		4,672.2							4,776.8					4,672.2		4,776.8
Total Long-term Debt Outstanding		4,981.6							5,601.5					4,981.6		5,601.5
Liabilities Held for Sale		0												0
Transmission and Distribution Companies [Member] | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net														94.1		164.6		261
AEP Transmission Holdco
Reportable Segment Information
Sales Revenue, Net														145.9		100.6		73.9
Revenues														512.8		329.2		191.9
Asset Impairments and Other Related Charges														0
Depreciation and Amortization														67.1		43		23.7
Interest and Investment Income														0.4		0.2		0
Carrying Costs Income														(0.3)		(0.2)		0
Interest Expense														50.3		37.2		23.5
Income Tax Expense (Credit)														134.1		91.3		62.9
Income from Continuing Operations														269.3		192.7		150.8
Income from Discontinued Operations, Net of Tax														0		0		0
NET INCOME (LOSS)														269.3		192.7		150.8
Gross Property Additions														1,265.8		1,121.3		948.3
Balance Sheet Information
Total Property, Plant and Equipment		5,354							3,977.6					5,354		3,977.6
Accumulated Depreciation and Amortization		101.4							52.3					101.4		52.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,252.6							3,925.3					5,252.6		3,925.3
Assets Held for Sale		0												0
Total Assets		6,384.8							5,012.1					6,384.8		5,012.1		3,570
Investments in Equity Method Investees		742							630.8					742		630.8
Long-term Debt Due Within One Year		0							0					0		0
Long-term Debt - Affiliated		0							0					0		0
Long-term Debt		2,055.7							1,648.4					2,055.7		1,648.4
Total Long-term Debt Outstanding		2,055.7							1,648.4					2,055.7		1,648.4
Liabilities Held for Sale		0												0
AEP Transmission Holdco | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net														366.9		228.6		118
Generation and Marketing [Member]
Reportable Segment Information
Sales Revenue, Net														2,858.7		2,866.7		2,384.3	[9]
Revenues														2,986		3,412.7		3,849.6
Asset Impairments and Other Related Charges														2,257.3
Depreciation and Amortization														154.6		201.4		226.8
Interest and Investment Income														1.4		2.8		4.7
Carrying Costs Income														0		0		0
Interest Expense														35.8		40		45.3
Income Tax Expense (Credit)														(666.5)		194.6		179.3
Income from Continuing Operations														(1,198)		366		367.4
Income from Discontinued Operations, Net of Tax														0		0		0
NET INCOME (LOSS)														(1,198)		366		367.4
Gross Property Additions														336.2		134.3		164.9
Balance Sheet Information
Total Property, Plant and Equipment		364.7							7,461.3					364.7		7,461.3
Accumulated Depreciation and Amortization		42.2							3,367					42.2		3,367
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		322.5							4,094.3					322.5		4,094.3
Assets Held for Sale		1,951.2												1,951.2
Total Assets		3,386.1							5,414.5					3,386.1		5,414.5		6,326.2
Investments in Equity Method Investees		0.1							0.1					0.1		0.1
Long-term Debt Due Within One Year		500.1							71.6					500.1		71.6
Long-term Debt - Affiliated		32.2							32.2					32.2		32.2
Long-term Debt		0							639.5					0		639.5
Total Long-term Debt Outstanding		532.3							743.3					532.3		743.3
Liabilities Held for Sale		235.9												235.9
Generation and Marketing [Member] | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net														127.3		546		1,465.3	[9]
All Other [Member]
Reportable Segment Information
Sales Revenue, Net	[10]													34.8		24		22.2
Revenues	[10]													105.1		99		95.4
Asset Impairments and Other Related Charges	[10]													0
Depreciation and Amortization	[10]													0.2		0.8		0
Interest and Investment Income	[10]													11.8		9.2		8.6
Carrying Costs Income	[10]													0		0		0
Interest Expense	[10]													40.5		30.3		25.1
Income Tax Expense (Credit)	[10]													(143.7)		(1.1)		15.2
Income from Continuing Operations	[10]													83.1		(42.7)		8.3
Income from Discontinued Operations, Net of Tax	[10]													(2.5)		283.7		47.5
NET INCOME (LOSS)	[10]													80.6		241		55.8
Gross Property Additions	[10]													9.8		4.8		17.2
Balance Sheet Information
Total Property, Plant and Equipment	[10]	356.6							350.9					356.6		350.9
Accumulated Depreciation and Amortization	[10]	186							176.9					186		176.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[10]	170.6							174					170.6		174
Assets Held for Sale	[10]	0												0
Total Assets	[10]	20,354.8							20,242.2					20,354.8		20,242.2		20,512.9
Investments in Equity Method Investees	[10]	24.9							56.8					24.9		56.8
Long-term Debt Due Within One Year	[10]	548.6							0.1					548.6		0.1
Long-term Debt - Affiliated	[10]	0							0					0		0
Long-term Debt	[10]	297.2							843.2					297.2		843.2
Total Long-term Debt Outstanding	[10]	845.8							$ 843.3					845.8		843.3
Liabilities Held for Sale	[10]	$ 0												0
All Other [Member] | Segment Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net	[10]													$ 70.3		$ 75		$ 73.2
[1]	Includes impairments for Merchant Generating Assets (see Note 7).
[2]	Includes final accounting adjustment for sale of AEPRO (see Note 7).
[3]	Includes sale of AEPRO (see Note 7).
[4]	Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
[5]	.
[6]	Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio.
[7]	Includes eliminations due to an intercompany capital lease.
[8]	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.
[9]	Includes the impact of the corporate separation of OPCo’s generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014.
[10]	Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent’s guarantee revenue received from affiliates, investment income, interest income, interest expense and discontinued operations of AEPRO and other nonallocated costs.

Derivatives and Hedging (Detail

Derivatives and Hedging (Details) gal in Millions, T in Millions, MWh in Millions, MMBTU in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2016USD ($)MWhMMBTUTgal		Dec. 31, 2015USD ($)MWhMMBTUTgal		Dec. 31, 2014USD ($)
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 7.9		$ 5.8
Cash Collateral Paid Netted Against Risk Management Liabilities		7.6		44.4
Fair Value of Derivative Instruments
Current Risk Management Assets		94.5		134.4
Long-term Risk Management Assets		289.1		321.8
Total Assets		383.6		456.2
Current Risk Management Liabilities		53.4		87.1
Long-term Risk Management Liabilities		316.2		179.1
Total Liabilities		369.6		266.2
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		28.4		86.4		$ 269.7
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments		1.6		3.2		3.8
Gain (Loss) on Fair Value Portion of Long-term Debt		(1.6)		(3.3)		(3.9)
Collateral Triggering Events [Abstract]
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		9.3		17.5
Amount of Collateral Attributable to Other Contracts	[1]	280.3		297.8
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		259.6		300.1
Amount of Cash Collateral Posted		0.4		0.8
Additional Settlement Liability if Cross Default Provision is Triggered		$ 235.8		240.6
Derivatives and Hedging (Textuals) [Abstract]
Maximum Length of Time Hedged in Price Risk Cash Flow Hedge		132 months
Appalachian Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 0.5		0
Cash Collateral Paid Netted Against Risk Management Liabilities		0.7		3.1
Fair Value of Derivative Instruments
Current Risk Management Assets		2.6		14.7
Long-term Risk Management Assets		0		0.1
Current Risk Management Liabilities		0.3		4.8
Long-term Risk Management Liabilities		0.9		0.1
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		56.5		36.5		54.2
Collateral Triggering Events [Abstract]
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		1		4.9
Amount of Collateral Attributable to Other Contracts		0		0.1
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		0.1		3.7
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		0		3.7
Indiana Michigan Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0.3		0
Cash Collateral Paid Netted Against Risk Management Liabilities		0.4		0.6
Fair Value of Derivative Instruments
Current Risk Management Assets		3.5		10.6
Current Risk Management Liabilities		0.3		6.3
Long-term Risk Management Liabilities		0.8		1.6
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		27		15.9		49.2
Collateral Triggering Events [Abstract]
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		0.6		3.3
Amount of Collateral Attributable to Other Contracts		0		0.1
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements		0.1		2.5
Amount of Cash Collateral Posted		0		0
Additional Settlement Liability if Cross Default Provision is Triggered		0		2.5
Ohio Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0.2		0
Cash Collateral Paid Netted Against Risk Management Liabilities		0		0.5
Fair Value of Derivative Instruments
Current Risk Management Assets		0.2		0
Long-term Risk Management Assets		0		19.2
Current Risk Management Liabilities		5.9		3.6
Long-term Risk Management Liabilities		113.1		0
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(143.5)		(30.1)		86
Public Service Co Of Oklahoma [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0.1		0
Cash Collateral Paid Netted Against Risk Management Liabilities		0		0.3
Fair Value of Derivative Instruments
Current Risk Management Assets		0.8		0.6
Current Risk Management Liabilities		0		0.2
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		6.6		4.2		0.4
Collateral Triggering Events [Abstract]
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		2.1		0
Amount of Collateral Attributable to Other Contracts		3.2		3.2
Southwestern Electric Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0.1		0
Cash Collateral Paid Netted Against Risk Management Liabilities		0		0.3
Fair Value of Derivative Instruments
Current Risk Management Assets		0.9		0.8
Current Risk Management Liabilities		0.3		3.1
Long-term Risk Management Liabilities		0		2.1
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		20.4		9.9		15.8
Collateral Triggering Events [Abstract]
Amount of Collateral the Registrants Would Have Been Required to Post Attributable to RTOs and ISOs		2.5		0
Amount of Collateral Attributable to Other Contracts		0.1		0.1
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[2]	372.4	[3]	438.5	[4]
Total Liabilities	[2]	321.5	[3]	236.6	[4]
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	2.6		15.7
Total Liabilities	[2],[5]	1.2		4.9
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	3.5		12.3
Total Liabilities	[2],[5]	1.1		7.9
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	0.2		19.2
Total Liabilities	[2],[5]	119		3.6
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	0.8		0.6
Total Liabilities	[2],[5]			0.2
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[2],[5]	0.9		0.8
Total Liabilities	[2],[5]	0.3		5.2
Commodity [Member]
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	11.2		17.6
Hedging Liabilities	[6]	46.7		26.1
AOCI Gain (Loss) Net of Tax		(23.1)		(5.2)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		4.3		(0.4)
Derivatives and Hedging (Textuals) [Abstract]
Cross Default Provisions Maximum Third Party Obligation Amount		50
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	264.4		368.8
Long-term Risk Management Assets	[7]	315		364.8
Total Assets	[7]	579.4		733.6
Current Risk Management Liabilities	[7]	227.2		347
Long-term Risk Management Liabilities	[7]	301		223.3
Total Liabilities	[7]	528.2		570.3
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	51.2		163.3
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	22.7		25.9
Long-term Risk Management Assets	[8]	1.9		0.3
Total Assets	[8]	24.6		26.2
Current Risk Management Liabilities	[8]	20.6		18.1
Long-term Risk Management Liabilities	[8]	2.8		0.3
Total Liabilities	[8]	23.4		18.4
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	1.2		7.8
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	14.9		22.8
Long-term Risk Management Assets	[8]	1.1		0.6
Total Assets	[8]	16		23.4
Current Risk Management Liabilities	[8]	11.8		17
Long-term Risk Management Liabilities	[8]	1.9		2.6
Total Liabilities	[8]	13.7		19.6
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	2.3		3.8
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0.4		0
Long-term Risk Management Assets	[8]	0		19.2
Total Assets	[8]	0.4		19.2
Current Risk Management Liabilities	[8]	5.9		4.1
Long-term Risk Management Liabilities	[8]	113.1		0
Total Liabilities	[8]	119		4.1
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	(118.6)		15.1
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	0.9		0.6
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	0.9		0.6
Current Risk Management Liabilities	[8]	0		0.5
Long-term Risk Management Liabilities	[8]	0		0
Total Liabilities	[8]	0		0.5
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0.9		0.1
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[8]	1.1		0.8
Long-term Risk Management Assets	[8]	0		0
Total Assets	[8]	1.1		0.8
Current Risk Management Liabilities	[8]	0.4		3.4
Long-term Risk Management Liabilities	[8]	0		2.1
Total Liabilities	[8]	0.4		5.5
Total MTM Derivative Contract Net Assets (Liabilities)	[8]	0.7		(4.7)
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	13.2		8.2
Long-term Risk Management Assets	[7]	7.7		11.7
Total Assets	[7]	20.9		19.9
Current Risk Management Liabilities	[7]	6.3		9.1
Long-term Risk Management Liabilities	[7]	50.1		19.3
Total Liabilities	[7]	56.4		28.4
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(35.5)		(8.5)
Interest Rate and Foreign Currency [Member]
Commodity
Derivative, Notional Amount		500		560.3
Impact of Cash Flow Hedges on the Balance Sheet
Hedging Assets	[6]	0		0
Hedging Liabilities	[6]	0		0.4
AOCI Gain (Loss) Net of Tax		(15.7)		(17.2)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1)		(1.5)
Interest Rate and Foreign Currency [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		2.9		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
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		(12)		(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
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		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
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		3.4		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
Impact of Cash Flow Hedges on the Balance Sheet
AOCI Gain (Loss) Net of Tax		(7.4)		(9.1)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months		(1.4)		(1.7)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[7]	0		0.1
Long-term Risk Management Assets	[7]	0		0
Total Assets	[7]	0		0.1
Current Risk Management Liabilities	[7]	0		0.3
Long-term Risk Management Liabilities	[7]	1.4		3.2
Total Liabilities	[7]	1.4		3.5
Total MTM Derivative Contract Net Assets (Liabilities)	[7]	(1.4)		(3.4)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		277.6		377.1
Long-term Risk Management Assets		322.7		376.5
Total Assets		600.3		753.6
Current Risk Management Liabilities		233.5		356.4
Long-term Risk Management Liabilities		352.5		245.8
Total Liabilities		586		602.2
Total MTM Derivative Contract Net Assets (Liabilities)		14.3		151.4
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	(183.1)		(242.7)
Long-term Risk Management Assets	[9]	(33.6)		(54.7)
Total Assets	[9]	(216.7)		(297.4)
Current Risk Management Liabilities	[9]	(180.1)		(269.3)
Long-term Risk Management Liabilities	[9]	(36.3)		(66.7)
Total Liabilities	[9]	(216.4)		(336)
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(0.3)		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]	(20.1)		(10.3)
Long-term Risk Management Assets	[10]	(1.9)		(0.2)
Total Assets	[10]	(22)		(10.5)
Current Risk Management Liabilities	[10]	(20.3)		(13.3)
Long-term Risk Management Liabilities	[10]	(1.9)		(0.2)
Total Liabilities	[10]	(22.2)		(13.5)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.2		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]	(11.4)		(10.5)
Long-term Risk Management Assets	[10]	(1.1)		(0.6)
Total Assets	[10]	(12.5)		(11.1)
Current Risk Management Liabilities	[10]	(11.5)		(10.7)
Long-term Risk Management Liabilities	[10]	(1.1)		(1)
Total Liabilities	[10]	(12.6)		(11.7)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0.1		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]	(0.2)		0
Long-term Risk Management Assets	[10]	0		0
Total Assets	[10]	(0.2)		0
Current Risk Management Liabilities	[10]	0		(0.5)
Long-term Risk Management Liabilities	[10]	0		0
Total Liabilities	[10]	0		(0.5)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	(0.2)		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
Long-term Risk Management Assets	[10]	0		0
Total Assets	[10]	(0.1)		0
Current Risk Management Liabilities	[10]	0		(0.3)
Long-term Risk Management Liabilities	[10]	0		0
Total Liabilities	[10]	0		(0.3)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	(0.1)		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]	(0.2)		0
Long-term Risk Management Assets	[10]	0		0
Total Assets	[10]	(0.2)		0
Current Risk Management Liabilities	[10]	(0.1)		(0.3)
Long-term Risk Management Liabilities	[10]	0		0
Total Liabilities	[10]	(0.1)		(0.3)
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	(0.1)		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]	94.5		134.4
Long-term Risk Management Assets	[11]	289.1		321.8
Total Assets	[11]	383.6		456.2
Current Risk Management Liabilities	[11]	53.4		87.1
Long-term Risk Management Liabilities	[11]	316.2		179.1
Total Liabilities	[11]	369.6		266.2
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	14		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]	2.6		15.6
Long-term Risk Management Assets	[12]	0		0.1
Total Assets	[12]	2.6		15.7
Current Risk Management Liabilities	[12]	0.3		4.8
Long-term Risk Management Liabilities	[12]	0.9		0.1
Total Liabilities	[12]	1.2		4.9
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	1.4		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]	3.5		12.3
Long-term Risk Management Assets	[12]	0		0
Total Assets	[12]	3.5		12.3
Current Risk Management Liabilities	[12]	0.3		6.3
Long-term Risk Management Liabilities	[12]	0.8		1.6
Total Liabilities	[12]	1.1		7.9
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	2.4		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]	0.2		0
Long-term Risk Management Assets	[12]	0		19.2
Total Assets	[12]	0.2		19.2
Current Risk Management Liabilities	[12]	5.9		3.6
Long-term Risk Management Liabilities	[12]	113.1		0
Total Liabilities	[12]	119		3.6
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	(118.8)		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]	0.8		0.6
Long-term Risk Management Assets	[12]	0		0
Total Assets	[12]	0.8		0.6
Current Risk Management Liabilities	[12]	0		0.2
Long-term Risk Management Liabilities	[12]	0		0
Total Liabilities	[12]	0		0.2
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	0.8		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]	0.9		0.8
Long-term Risk Management Assets	[12]	0		0
Total Assets	[12]	0.9		0.8
Current Risk Management Liabilities	[12]	0.3		3.1
Long-term Risk Management Liabilities	[12]	0		2.1
Total Liabilities	[12]	0.3		5.2
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	$ 0.6		$ (4.4)
Power [Member]
Commodity
Derivative, Energy Notional Amount | MWh		348		317.8
Power [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		51.9		40.9
Power [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		19.9		22.8
Power [Member] | Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		11.2		13.3
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount | MWh		11.9		11.3
Power [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MWh		14.2		14
Coal [Member]
Commodity
Derivative, Mass Notional Amount | T		1.5		4.4
Coal [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		0.5		1.6
Coal [Member] | Ohio Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Mass Notional Amount | T		0		0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Mass Notional Amount | T		1		2.8
Natural Gas [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		32.8		38.2
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0.3
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0.2
Natural Gas [Member] | Ohio Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0
Natural Gas [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0.2
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Energy Notional Amount | MMBTU		0		0.2
Heating Oil and Gasoline [Member]
Commodity
Derivative, Volume Notional Amount | gal		7.4		7.4
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.4		1.4
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.7		0.7
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		1.6		1.6
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.8		0.8
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Volume Notional Amount | gal		0.9		0.9
Interest Rate Contract [Member]
Commodity
Derivative, Notional Amount		$ 75.2		$ 113.5
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity
Derivative, Notional Amount		0.1		2.4
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity
Derivative, Notional Amount		0.1		1.6
Interest Rate Contract [Member] | Ohio Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member]
Commodity
Derivative, Notional Amount		0		0
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member]
Commodity
Derivative, Notional Amount		0		0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		4		6.7		35.4
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		(4.3)
Transmission and Distribution Utilities Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Transmission and Distribution Utilities Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Transmission and Distribution Utilities Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Transmission and Distribution Utilities Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Transmission and Distribution Utilities Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Generation and Marketing Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		59.4		54.9		52.5
Generation and Marketing Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Generation and Marketing Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Electric Generation, Transmission and Distribution Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Electric Generation, Transmission and Distribution Revenues [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.6)		1.1		8.7
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		4.1		3.3		13.2
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		(4.3)		0
Electric Generation, Transmission and Distribution Revenues [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0.2
Electric Generation, Transmission and Distribution Revenues [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
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		2.1		2.4		0
Sales to AEP Affiliates [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		5.8		8.2		(0.9)
Sales to AEP Affiliates [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		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		0.9
Sales to AEP Affiliates [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0		0
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		6.6		6.4
Purchased Electricity for Resale [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		3.5		2
Purchased Electricity for Resale [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0.3		0.4
Purchased Electricity for Resale [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Purchased Electricity for Resale [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(1.6)		(3.3)
Other Operation Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.4)
Other Operation Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.4)
Other Operation Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.3)		(0.6)
Other Operation Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.4)
Other Operation Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.3)		(0.5)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(1.8)		(3.3)
Maintenance Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.4)		(0.7)
Maintenance Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.1)		(0.4)
Maintenance Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.4)		(0.5)
Maintenance Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.2)		(0.4)
Maintenance Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(0.2)		(0.4)
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	(117.4)		(0.9)		(11.4)
Regulatory Assets [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	0.6		3.4		(4.1)
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]	3.1		(2.7)		(0.5)
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]	(127.7)		0		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]	0.4		0.6		(1)
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]	5.2		(4.3)		(1.1)
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	79.1		30.2		193.2
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]	51.4		28.7		49.6
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]	13.9		7.5		37.4
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]	(15.2)		(24.7)		86
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]	6.5		4.4		0.3
Regulatory Liabilities [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[13]	$ 15.7		$ 15.1		$ 16.9
[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 contracts.
[2]	Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
[3]	The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts.
[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 these categories are reported gross. These instruments are subject to master netting agreements and are presented on the balance sheets on a net basis in accordance with the accounting guidance for “Derivatives and Hedging.”
[9]	Amounts primarily include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[10]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for “Derivatives and Hedging.”
[11]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[12]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[13]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the balance sheets.

Fair Value Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2016	Dec. 31, 2015
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					$ 20,256.4	$ 19,572.7	[1]
Long-term Debt, Fair Value					22,211.9	21,201.3
Other Temporary Investments
Cost					318.8	375.8
Gross Unrealized Gains					13.9	11.7
Gross Unrealized Losses					(1)	(0.7)
Estimated Fair Value					331.7	386.8
Debt and Equity Securities Within Other Temporary Investments [Abstract]
Proceeds From Investment Sales		$ 0	$ 0	$ 0
Purchases of Investments		2.3	10.7	1.6
Gross Realized Gains on Investment Sales		0	0	0
Gross Realized Losses on Investment Sales		0	0	0
Nuclear Trust Fund Investments
Estimated Fair Value		2,256.2	2,106.4		2,256.2	2,106.4
Gross Unrealized Gains					707.7	611.8
Other-Than-Temporary Impairments					(87.2)	(83.3)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,957.7	2,218.4	1,031.8
Purchases of Investments		3,000	2,272	1,086.4
Gross Realized Gains on Investment Sales		46.1	69.1	32.3
Gross Realized Losses on Investment Sales		24.4	53	15.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,256.2	2,106.4
Fair Value Measurements (Textuals) [Abstract]
Adjusted Cost of Debt Securities					938	771
Adjusted Cost of Domestic Equity Securities					592	555
Includes Debt Included In Liabilities Held For Sale [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding	[2]				20,391.2
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					4,033.9	3,930.7
Long-term Debt, Fair Value					4,613.2	4,416.7
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					2,471.4	2,000
Long-term Debt, Fair Value					2,661.6	2,193.6
Nuclear Trust Fund Investments
Estimated Fair Value		2,256.2	2,106.4		2,256.2	2,106.4
Gross Unrealized Gains					707.7	611.8
Other-Than-Temporary Impairments					(87.2)	(83.3)
Securities Activity Within the Decommissioning and SNF Trusts
Proceeds from Investment Sales		2,957.7	2,218.4	1,031.8
Purchases of Investments		3,000	2,272	1,086.4
Gross Realized Gains on Investment Sales		46.1	69.1	32.3
Gross Realized Losses on Investment Sales		24.4	53	$ 15.4
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,256.2	2,106.4
Fair Value Measurements (Textuals) [Abstract]
Adjusted Cost of Debt Securities					938	771
Adjusted Cost of Domestic Equity Securities					592	555
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					1,763.9	2,157.7
Long-term Debt, Fair Value					2,092.5	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	1,286.1
Long-term Debt, Fair Value					1,419	1,402.9
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding					2,679.1	2,273.5
Long-term Debt, Fair Value					2,814.3	2,417.2
Cash [Member]
Other Temporary Investments
Cost	[3]				211.7	271
Gross Unrealized Gains	[3]				0	0
Gross Unrealized Losses	[3]				0	0
Estimated Fair Value	[3],[4]				211.7	271
Fixed Income Funds [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		967.4	811.2		967.4	811.2
Gross Unrealized Gains					29.8	40.2
Other-Than-Temporary Impairments					(7.6)	(4)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		967.4	811.2
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		967.4	811.2		967.4	811.2
Gross Unrealized Gains					29.8	40.2
Other-Than-Temporary Impairments					(7.6)	(4)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		967.4	811.2
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost	[5]				92.7	91.1
Gross Unrealized Gains	[5]				0	0
Gross Unrealized Losses	[5]				(1)	(0.7)
Estimated Fair Value	[5]				91.7	90.4
Domestic [Member]
Nuclear Trust Fund Investments
Estimated Fair Value	[6]	1,270.1	1,126.9		1,270.1	1,126.9
Gross Unrealized Gains					677.9	571.6
Other-Than-Temporary Impairments					(79.6)	(79.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	1,270.1	1,126.9
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value	[6]	1,270.1	1,126.9		1,270.1	1,126.9
Gross Unrealized Gains					677.9	571.6
Other-Than-Temporary Impairments					(79.6)	(79.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	1,270.1	1,126.9
Mutual Funds Equity [Member]
Other Temporary Investments
Cost					14.4	13.7
Gross Unrealized Gains					13.9	11.7
Gross Unrealized Losses					0	0
Estimated Fair Value					28.3	25.4
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments
Estimated Fair Value	[7]	18.7	168.3		18.7	168.3
Gross Unrealized Gains					0	0
Other-Than-Temporary Impairments					0	0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[7]	18.7	168.3
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value	[7]	18.7	168.3		18.7	168.3
Gross Unrealized Gains					0	0
Other-Than-Temporary Impairments					0	0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[7]	18.7	168.3
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		785.4	731.1		785.4	731.1
Gross Unrealized Gains					27.1	35.9
Other-Than-Temporary Impairments					(5.5)	(2.6)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		785.4	731.1
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		785.4	731.1		785.4	731.1
Gross Unrealized Gains					27.1	35.9
Other-Than-Temporary Impairments					(5.5)	(2.6)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		785.4	731.1
Corporate Debt Securities [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		60.9	57.9		60.9	57.9
Gross Unrealized Gains					2.3	3.2
Other-Than-Temporary Impairments					(1.4)	(1.1)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		60.9	57.9
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		60.9	57.9		60.9	57.9
Gross Unrealized Gains					2.3	3.2
Other-Than-Temporary Impairments					(1.4)	(1.1)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		60.9	57.9
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		121.1	22.2		121.1	22.2
Gross Unrealized Gains					0.4	1.1
Other-Than-Temporary Impairments					(0.7)	(0.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		121.1	22.2
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		121.1	22.2		121.1	22.2
Gross Unrealized Gains					0.4	1.1
Other-Than-Temporary Impairments					(0.7)	$ (0.3)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		121.1	$ 22.2
Within One Year [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		229.5			229.5
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		229.5
Within One Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		229.5			229.5
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		229.5
One Year To Five Year [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		335.3			335.3
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		335.3
One Year To Five Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		335.3			335.3
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		335.3
Five Year To Ten Year [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		204.6			204.6
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		204.6
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		204.6			204.6
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		204.6
After 10 years [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		198			198
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		198
After 10 years [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments
Estimated Fair Value		198			$ 198
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		$ 198
[1]	.
[2]	Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 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 Financial Assets Lia

Fair Value Financial Assets Liabilities (Details) $ in Millions		12 Months Ended
		Dec. 31, 2016USD ($)$ / MWh		Dec. 31, 2015USD ($)$ / MWh		Dec. 31, 2013USD ($)
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 210.5		$ 176.4
Other Temporary Investments		331.7		386.8
Risk Management Assets
Risk Management Assets		383.6		456.2
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,256.2		2,106.4
Total Assets		3,182		3,125.8
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		369.6		266.2
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		146.9		150.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	42.8		13.5		$ 90
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	26.1		53.7		0.7
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		(23)		(4.9)		5.7
Settlements		(71.4)		(63)		(108.7)
Transfers into Level 3	[4],[5]	13.3		28.7		(7.6)
Transfers out of Level 3	[5]	(2.6)		(18.9)		(21.5)
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(129.6)		(13)		74.3
Ending Balance		$ 2.5		$ 146.9		117.9
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk				6.70%
Low [Member]
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk		0.35%
High [Member]
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk		8.24%
Weighted Average [Member]
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk		3.91%
Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 201.8		$ 168.2
Other Temporary Investments		32.8		33.3
Risk Management Assets
Risk Management Assets		(213)		(286.9)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		11.4		7.8
Total Assets		33		(77.6)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		(212.7)		(325.5)
Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	8.7		3.9
Other Temporary Investments		293.8		345.8
Risk Management Assets
Risk Management Assets		6		11.5
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,277.4		1,287.4
Total Assets		1,585.9		1,648.6
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		8.2		24.1
Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		4.3
Other Temporary Investments		5.1		7.7
Risk Management Assets
Risk Management Assets		396.7		510.9
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		967.4		811.2
Total Assets		1,369.2		1,334.1
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		382.7		493.8
Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Other Temporary Investments		0		0
Risk Management Assets
Risk Management Assets		193.9		220.7
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		193.9		220.7
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		191.4		73.8
2016 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				(9)
2016 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				2
2016 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				28
2017 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		20
2017 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		17
2017 - 2019 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				(4)
2017 - 2019 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				18
2017 - 2019 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				29
2018 - 2020 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		(2)
2018 - 2020 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		4
2018 - 2020 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		28
2020 - 2021 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				4
2020 - 2021 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				19
2021 - 2022 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		3
2021 - 2022 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		11
2022 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities				76
2023 - 2032 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		1
2023 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity Of Net Fair Value Of Risk Management Contracts Prior To Cash Collateral Assets Or Liabilities		(31)
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7]	372.4	[8]	438.5	[9]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	321.5	[8]	236.6	[9]
Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	(205.7)	[8]	(287.7)	[9]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	(205.4)	[8]	(326.3)	[9]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	6	[8]	11.5	[9]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	8.2	[8]	24.1	[9]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	379.9	[8]	495	[9]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	352	[8]	471.5	[9]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	192.2	[8]	219.7	[9]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	166.7	[8]	67.3	[9]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		183.8		212.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 187.1		$ 70.3
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	6.51		9.69
Forward Price Range High | $ / MWh	[10]	86.59		165.36
Weighted Average Market Price | $ / MWh	[10]	39.40		36.35
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 10.1		$ 8.4
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 4.3		$ 3.5
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	(7.99)		(6.99)
Forward Price Range High | $ / MWh	[10]	8.91		10.34
Weighted Average Market Price | $ / MWh	[10]	0.86		1.10
Commodity [Member]
Risk Management Assets
Risk Management Assets	[7]	$ 11.2		$ 17.6
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	46.7		26.1
Commodity [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7]	(7.3)		0.7
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	(7.3)		0.7
Commodity [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	0		0
Commodity [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7]	16.8		15.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	29.3		18.9
Commodity [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7]	1.7		1
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7]	24.7		6.5
Interest Rate Foreign Currency Hedges [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities				0.4
Interest Rate Foreign Currency Hedges [Member] | Other [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities				0
Interest Rate Foreign Currency Hedges [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities				0
Interest Rate Foreign Currency Hedges [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities				0.4
Interest Rate Foreign Currency Hedges [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities				0
Fair Value Hedging [Member]
Risk Management Assets
Risk Management Assets				0.1
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		1.4		3.1
Fair Value Hedging [Member] | Other [Member]
Risk Management Assets
Risk Management Assets				0.1
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0		0.1
Fair Value Hedging [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets				0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0		0
Fair Value Hedging [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets				0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		1.4		3
Fair Value Hedging [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets				0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0		0
Appalachian Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	15.9		14.9
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		18.5		30.6
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance	[11]	11.7		15.8
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	25.6	[11]	2.1	[11]	29.7
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0	[11]	0	[11]	0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0	[11]	0	[11]	0
Settlements		(37.5)	[11]	(17.2)	[11]	(32.6)
Transfers into Level 3	[4],[5]	0	[11]	0	[11]	(3.6)
Transfers out of Level 3	[5]	0.1	[11]	1.2	[11]	0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	1.5	[11]	9.8	[11]	11.7
Ending Balance		1.4	[11]	11.7	[11]	10.6
Appalachian Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0.1		0.1
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(21.7)		(10.5)
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	15.8		14.8
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15.8		15
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		20.5		13.9
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Risk Management Assets
Risk Management Assets		3.9		12.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		3.9		12.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		2.5		0.5
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	2.6		15.7
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	1.2		4.9
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(21.8)		(10.6)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	(22)		(13.6)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0		0.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0		0.2
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	20.5		13.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	20.7		17.8
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	3.9		12.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	2.5		0.5
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.4		7.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.4		$ 0.2
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	19.68		12.61
Forward Price Range High | $ / MWh	[10]	48.55		47.24
Weighted Average Market Price | $ / MWh	[10]	36.34		32.38
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 3.5		$ 4.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 2.1		$ 0.3
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	(0.23)		(6.96)
Forward Price Range High | $ / MWh	[10]	8.91		8.43
Weighted Average Market Price | $ / MWh	[10]	2.37		1.34
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,256.2		$ 2,106.4
Total Assets		2,259.7		2,118.7
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance	[11]	4.3		14.7
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	7.1	[11]	0.2	[11]	18.6
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0	[11]	0	[11]	0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0	[11]	0	[11]	0
Settlements		(11.1)	[11]	(14.2)	[11]	(20.6)
Transfers into Level 3	[4],[5]	0	[11]	0	[11]	(2.5)
Transfers out of Level 3	[5]	0.1	[11]	0.8	[11]	0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	2.4	[11]	2.8	[11]	12
Ending Balance		2.8	[11]	4.3	[11]	7.2
Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		11.4		7.8
Total Assets		(0.9)		(3.3)
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,277.4		1,287.4
Total Assets		1,277.4		1,287.5
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		967.4		811.2
Total Assets		980.2		828.2
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		3		6.3
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Total Assets		3		6.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0.2		2
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	3.5		12.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	1.1		7.9
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(12.3)		(11.1)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	(12.4)		(11.7)
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0		0.1
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0		0.1
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	12.8		17
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	13.3		17.5
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	3		6.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0.2		2
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.3		6
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.2		$ 0.2
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	19.68		12.61
Forward Price Range High | $ / MWh	[10]	48.55		47.24
Weighted Average Market Price | $ / MWh	[10]	36.34		32.38
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 2.7		$ 0.3
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0		$ 1.8
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	(7.9)		(6.96)
Forward Price Range High | $ / MWh	[10]	8.91		8.43
Weighted Average Market Price | $ / MWh	[10]	1.32		1.34
Ohio Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 27.2		$ 27.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		27.4		46.9
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		15.9		48.4
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	(3)		0.5		30.8
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		6.2		(6.7)		(33.7)
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	(138.1)		(26.3)		48.4
Ending Balance		$ (119)		15.9		2.9
Ohio Power Co [Member] | Low [Member]
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk		0.47%
Ohio Power Co [Member] | High [Member]
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk		3.40%
Ohio Power Co [Member] | Weighted Average [Member]
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk		2.72%
Ohio Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 27.2		27.7
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		27		30.9
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0		0
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.4		0
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Risk Management Assets
Risk Management Assets		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0		16
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		119
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.2		19.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	119		3.6
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(0.2)		3.2
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0		2.7
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0		0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.4		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0		0.8
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0		16
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	119		0.1
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0		16
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 119		$ 0.1
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	30.14		41.61
Forward Price Range High | $ / MWh	[10]	71.85		165.36
Weighted Average Market Price | $ / MWh	[10]	47.45		86.84
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		$ 0.6		$ (0.3)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	(1)		(0.2)		0
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		0.4		0.6		0
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	0.7		0.5		(0.3)
Ending Balance		0.7		0.6		0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.8		0.6
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]			0.2
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(0.1)		(0.1)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]			(0.4)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.2		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]			0.5
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.7		0.7
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]			0.1
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.7		0.7
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0		$ 0.1
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	(7.99)		(6.96)
Forward Price Range High | $ / MWh	[10]	1.03		8.43
Weighted Average Market Price | $ / MWh	[10]	(0.36)		1.34
Southwestern Electric Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 10.3		$ 5.2
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		11.2		6
Changes in the Fair Value of Net Trading Derivatives and Other Investments
Beginning Balance		0.8		(0.5)
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	7.7		9.2		0
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	0		0		0
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income		0		0		0
Settlements		(8.4)		(8.7)		0
Transfers into Level 3	[4],[5]	0		0		0
Transfers out of Level 3	[5]	0		0		0
Changes in Fair Value Allocated to Regulated Jurisdiction	[6]	0.6		0.8		(0.5)
Ending Balance		0.7		0.8		$ 0
Southwestern Electric Power Co [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	1.6		1.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		1.4		1.5
Southwestern Electric Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	8.7		3.6
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		8.7		3.6
Southwestern Electric Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.3		0
Southwestern Electric Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0		0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		0.8		0.9
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.9		0.8
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0.3		5.2
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Other [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	(0.2)		(0.1)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	(0.1)		(0.4)
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0		0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.3		0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0.3		5.5
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[7],[12]	0.8		0.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[7],[12]	0.1		0.1
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0.8		0.9
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 0.1		$ 0.1
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[10]	(7.99)		(6.96)
Forward Price Range High | $ / MWh	[10]	1.03		8.43
Weighted Average Market Price | $ / MWh	[10]	(0.36)		1.34
Cash [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1],[13]	$ 211.7		$ 271
Cash [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	32.8		33.3
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	173.8		230
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	5.1		7.7
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	0		0
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		967.4		811.2
Fixed Income Funds [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		967.4		811.2
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		967.4		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
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		967.4		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
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[14]	91.7		90.4
Mutual Funds Fixed Income [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		91.7		90.4
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0		0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[15]	28.3		25.4
Mutual Funds Equity [Member] | Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[15]	0		0
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[15]	28.3		25.4
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[15]	0		0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[15]	0		0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	18.7		168.3
Cash and Cash Equivalents [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	11.4		7.8
Cash and Cash Equivalents [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	7.3		160.5
Cash and Cash Equivalents [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0		0
Cash and Cash Equivalents [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0		0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	18.7		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	[16]	11.4		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	[16]	7.3		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	[16]	0		0
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[16]	0		0
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		785.4		731.1
US Government Agencies Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		785.4		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
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		785.4		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
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		785.4		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
Corporate Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		60.9		57.9
Corporate Debt Securities [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		60.9		57.9
Corporate Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		60.9		57.9
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		60.9		57.9
Corporate Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		121.1		22.2
State and Local Jurisdiction [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		121.1		22.2
State and Local Jurisdiction [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		121.1		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
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0		0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		121.1		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
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,270.1		1,126.9
Domestic [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0		0
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,270.1		1,126.9
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0		0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,270.1		1,126.9
Domestic [Member] | Indiana Michigan Power Co [Member] | Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	1,270.1		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	[15]	0		0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[15]	$ 0		$ 0
[1]	Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[2]	Included in revenues on the statements of income.
[3]	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
[4]	Represents existing assets or liabilities that were previously categorized as Level 2.
[5]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[6]	Relates to the net gains (losses) of those contracts that are not reflected on the statements of income. These net gains (losses) are recorded as regulatory assets/liabilities.
[7]	Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for “Derivatives and Hedging.”
[8]	The December 31, 2016 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(2) million in 2018-2020; Level 2 matures $20 million in 2017, $4 million in periods 2018-2020, $3 million in periods 2021-2022 and $1 million in periods 2023-2032; Level 3 matures $17 million in 2017, $28 million in periods 2018-2020, $11 million in periods 2021-2022 and $(31) million in periods 2023-2032. Risk management commodity contracts are substantially comprised of power contracts.
[9]	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.
[10]	Represents market prices in dollars per MWh.
[11]	Includes both affiliated and nonaffiliated transactions.
[12]	Substantially comprised of power contracts for the Registrant Subsidiaries.
[13]	Primarily represents amounts held for the repayment of debt.
[14]	Primarily short and intermediate maturities which may be sold and do not contain maturity dates.
[15]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[16]	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.

Income Taxes (Details)

Income Taxes (Details) - USD ($) $ in Millions	3 Months Ended											12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016	Dec. 31, 2015		Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Federal:
Current												$ (30.7)	$ 107.3	$ 22.8
Deferred												(28.8)	774.8	800.1
Total Federal												(41.9)	882.1	822.9
State and Local:
Current												(10.5)	14.5	22.8
Deferred												(21.2)	23	56.9
Total State and Local												(31.8)	37.5	79.7
Income Tax Expense (Credit)												(73.7)	919.6	902.6
Income Tax Expense:
Deferred												(50)	808.2	868.8
Income Tax Expense (Credit)												(73.7)	919.6	902.6
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	$ 375.2	$ (764.2)	[1]	$ 503.9		$ 503.1	$ 470.7		$ 519.6	$ 431.3	$ 630.7	618	2,052.3	1,638
Discontinued Operations				2.5	[2]		(265.5)	[3]	(7.8)	0.1	(10.5)	2.5	(283.7)	(47.5)
Income Tax Expense (Credit)												(73.7)	919.6	902.6
Pretax Income												546.8	2,688.2	2,493.1
Income Taxes on Pretax Income at Statutory Rate (35%)												191.4	940.9	872.6
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												41.7	53.6	54
Investment Tax Credits, Net												(12.3)	(11.6)	(12.8)
State and Local Income Taxes, Net												(20.7)	24.4	54.3
Removal Costs												(39.8)	(28.8)	(23.9)
AFUDC												(44.8)	(51.6)	(41.8)
Valuation Allowance												(128.3)	17.2	(2.5)
Tax Adjustments												(43.9)	(20.1)	(10.1)
U.K. Windfall Tax												(12.9)	0	0
Other												(4.1)	(4.4)	12.8
Income Tax Expense (Credit)												$ (73.7)	$ 919.6	$ 902.6
Effective Income Tax Rate												(13.47842%)	34.20876%	36.20392%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	2,753						2,503.9					$ 2,753	$ 2,503.9
Deferred Tax Liabilities	(14,637.4)						(14,237.1)					(14,637.4)	(14,237.1)
Property Related Temporary Differences	(8,758.1)						(8,533.3)					(8,758.1)	(8,533.3)
Amounts Due from Customers for Future Federal Income Taxes	(292.2)						(263.5)					(292.2)	(263.5)
Deferred State Income Taxes	(976.6)						(872)					(976.6)	(872)
Securitized Assets	(535.6)						(633.2)					(535.6)	(633.2)
Regulatory Assets	(896.9)						(873.6)					(896.9)	(873.6)
Deferred Income Taxes on Other Comprehensive Loss	88.7						72.2					88.7	72.2
Accrued Nuclear Decommissioning	(666.8)						(614.6)					(666.8)	(614.6)
Net Operating Loss Carryforward	101.2						39.6					101.2	39.6
Tax Credit Carryforward	45.1						85					45.1	85
Valuation Allowance	(1.8)						(130)					(1.8)	(130)
All Other, Net	8.6						(9.8)					8.6	(9.8)
Net Deferred Tax Liabilities	(11,884.4)						(11,733.2)					(11,884.4)	(11,733.2)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												2.7	2.7	$ 2.9
Interest Income												9.9	0.8	1.2
Reversal of Prior Period Interest Expense												3.3	0	2
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	2.9						44.7					2.9	44.7
Accrual for Payment of Interest and Penalties	5.8						7.2					5.8	7.2
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,						187					182	187	182	175.2
Increase - Tax Positions Taken During a Prior Period												86	5.4	18.2
Decrease - Tax Positions Taken During a Prior Period												(161.2)	(0.4)	(1.5)
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Decrease - Settlements with Taxing Authorities												(13)	0	(0.6)
Decrease - Lapse of the Applicable Statute of Limitations												0	0	(9.3)
Balance at December 31,	98.8						187					98.8	187	182	$ 175.2
Unrecognized Tax Benefits, if Recognized - Amount	15.8						100.2					$ 15.8	$ 100.2	$ 97.2
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Federal Net Income Tax Operating Loss												$ 143
Income Tax Expense (Credit)												(73.7)	$ 919.6	$ 902.6
Interest Income												16.3	7.9	7.4
Net Income (Loss)	375.2	(764.2)	[1]	503.9		503.1	470.7		519.6	431.3	630.7	$ 618	2,052.3	$ 1,638
Period with No Change in Unrecognized Tax Benefits												12 months
Original Indiana Corporate Income Tax Rate												8.50%
Reduced Indiana Corporate Income Tax Rate												6.50%
Reduction In Indiana Corporate Tax Rate												0.50%
Indiana Corporate Tax Rate												4.90%
Original WV Corporate Income Tax Rate														7.00%
Reduced WV Corporate Income Tax														6.50%
Pre-2016 TX Income/Franchise Tax Rate												0.95%
New TX Income/Franchise Tax Rate												0.75%
Anticipated TX Income/Franchise Tax Rate												1.00%
Valuation Allowance	(1.8)						(130)					$ (1.8)	(130)
Transmission and Distribution Expenses Net Income Adjustment												21
Appalachian Power Co [Member]
Federal:
Current												64.1
Deferred												125.8
Deferred Investment Tax Credits													(0.3)	$ (0.7)
Total Federal												189.8
State and Local:
Current												4.4
Deferred												4.9
Deferred Investment Tax Credits													(0.3)	(0.7)
Total State and Local												9.3
Income Tax Expense (Credit)												199.1	194.3	154.9
Income Tax Expense:
Current													(32.9)	10.9
Deferred												130.7	227.5	144.7
Deferred Investment Tax Credits													(0.3)	(0.7)
Income Tax Expense (Credit)												199.1	194.3	154.9
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	65.3	104.1		73.4		126.3	65.2		74.6	59	141.8	369.1	340.6	215.4
Discontinued Operations				0			0		0	0	0
Income Tax Expense (Credit)												199.1	194.3	154.9
Pretax Income												568.2	534.9	370.3
Income Taxes on Pretax Income at Statutory Rate (35%)												198.9	187.2	129.6
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												19.3	19.8	23.5
Investment Tax Credits, Net												(0.1)	(0.3)	(0.6)
State and Local Income Taxes, Net												6	7.2	6.5
Removal Costs												(12)	(9.9)	(6.8)
AFUDC												(6.1)	(7)	(3.8)
Valuation Allowance												(1.7)	1.7	(2.5)
Other												(5.2)	(4.4)	9
Income Tax Expense (Credit)												$ 199.1	$ 194.3	$ 154.9
Effective Income Tax Rate												35.04048%	36.32455%	41.83095%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	413.5						412.9					$ 413.5	$ 412.9
Deferred Tax Liabilities	(3,085.8)						(2,939.9)					(3,085.8)	(2,939.9)
Property Related Temporary Differences	(2,031.9)						(1,866)					(2,031.9)	(1,866)
Amounts Due from Customers for Future Federal Income Taxes	(73.1)						(68.2)					(73.1)	(68.2)
Deferred State Income Taxes	(319.3)						(308.7)					(319.3)	(308.7)
Securitized Assets	(106.9)						(114.8)					(106.9)	(114.8)
Regulatory Assets	(159.9)						(169.1)					(159.9)	(169.1)
Deferred Income Taxes on Other Comprehensive Loss	4.5						1.5					4.5	1.5
Tax Credit Carryforward	11.7						19.2					11.7	19.2
All Other, Net	2.6						(20.9)					2.6	(20.9)
Net Deferred Tax Liabilities	(2,672.3)						(2,527)					(2,672.3)	(2,527)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0	0.4	$ 0
Interest Income												0.1	0	0
Reversal of Prior Period Interest Expense												0	0	0.2
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0						0					0	0
Accrual for Payment of Interest and Penalties	0.1						0					0.1	0
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,						0.3					0	0.3	0	1.2
Increase - Tax Positions Taken During a Prior Period												0	0.3	0
Decrease - Tax Positions Taken During a Prior Period												(0.3)	0	0
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Decrease - Settlements with Taxing Authorities												0	0	0
Decrease - Lapse of the Applicable Statute of Limitations												0	0	(1.2)
Balance at December 31,	0						0.3					0	0.3	0	1.2
Unrecognized Tax Benefits, if Recognized - Amount	0						0.2					$ 0	$ 0.2	$ 0
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Income Tax Expense (Credit)												$ 199.1	$ 194.3	$ 154.9
Net Income (Loss)	65.3	104.1		73.4		126.3	65.2		74.6	59	141.8	$ 369.1	340.6	$ 215.4
Period with No Change in Unrecognized Tax Benefits												12 months
Original Indiana Corporate Income Tax Rate												8.50%
Reduced Indiana Corporate Income Tax Rate												6.50%
Reduction In Indiana Corporate Tax Rate												0.50%
Indiana Corporate Tax Rate												4.90%
Original WV Corporate Income Tax Rate														7.00%
Reduced WV Corporate Income Tax														6.50%
Indiana Michigan Power Co [Member]
Federal:
Current												$ (44.8)
Deferred												104.9
Deferred Investment Tax Credits													(3.3)	$ (4.9)
Total Federal												63.9
State and Local:
Current												3.4
Deferred												0.2
Deferred Investment Tax Credits													(3.3)	(4.9)
Total State and Local												3.6
Income Tax Expense (Credit)												67.5	96.1	79.6
Income Tax Expense:
Current													5.2	14.3
Deferred												105.1	94.2	70.2
Deferred Investment Tax Credits													(3.3)	(4.9)
Income Tax Expense (Credit)												67.5	96.1	79.6
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	38.5	75.4		51.3		74.7	24.9		56.6	50.6	72.7	239.9	204.8	155.6
Discontinued Operations				0			0		0	0	0
Income Tax Expense (Credit)												67.5	96.1	79.6
Pretax Income												307.4	300.9	235.2
Income Taxes on Pretax Income at Statutory Rate (35%)												107.6	105.3	82.3
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												6.7	9.5	12.9
Investment Tax Credits, Net												(4.7)	(3.3)	(4.9)
State and Local Income Taxes, Net												2.4	5.8	7.7
Removal Costs												(21.3)	(12.6)	(11.3)
AFUDC												(7.3)	(6.2)	(10)
Tax Adjustments												(14.2)	(4.2)	1.2
Other												(1.7)	1.8	1.7
Income Tax Expense (Credit)												$ 67.5	$ 96.1	$ 79.6
Effective Income Tax Rate												21.95836%	31.93752%	33.84354%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	912.9						837.4					$ 912.9	$ 837.4
Deferred Tax Liabilities	(2,440.3)						(2,198.9)					(2,440.3)	(2,198.9)
Property Related Temporary Differences	(579.4)						(521.6)					(579.4)	(521.6)
Amounts Due from Customers for Future Federal Income Taxes	(50.4)						(42.7)					(50.4)	(42.7)
Deferred State Income Taxes	(158.7)						(124.8)					(158.7)	(124.8)
Regulatory Assets	(81)						(70.2)					(81)	(70.2)
Deferred Income Taxes on Other Comprehensive Loss	8.8						9					8.8	9
Accrued Nuclear Decommissioning	(666.8)						(614.6)					(666.8)	(614.6)
Net Operating Loss Carryforward	7.1						0					7.1	0
All Other, Net	(7)						3.4					(7)	3.4
Net Deferred Tax Liabilities	(1,527.4)						(1,361.5)					(1,527.4)	(1,361.5)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0.2	0.2	$ 0
Interest Income												0	0	0
Reversal of Prior Period Interest Expense												0	0	0.3
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0						0					0	0
Accrual for Payment of Interest and Penalties	0.9						0.6					0.9	0.6
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,						2.4					2.3	2.4	2.3	3.2
Increase - Tax Positions Taken During a Prior Period												1.8	0.1	1.4
Decrease - Tax Positions Taken During a Prior Period												(0.4)	0	0
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Decrease - Settlements with Taxing Authorities												0	0	(0.7)
Decrease - Lapse of the Applicable Statute of Limitations												0	0	(1.6)
Balance at December 31,	3.8						2.4					3.8	2.4	2.3	3.2
Unrecognized Tax Benefits, if Recognized - Amount	2.5						1.6					$ 2.5	$ 1.6	$ 1.6
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Federal Net Income Tax Operating Loss												$ 20
Income Tax Expense (Credit)												67.5	$ 96.1	$ 79.6
Net Income (Loss)	38.5	75.4		51.3		74.7	24.9		56.6	50.6	72.7	$ 239.9	204.8	$ 155.6
Period with No Change in Unrecognized Tax Benefits												12 months
Original Indiana Corporate Income Tax Rate												8.50%
Reduced Indiana Corporate Income Tax Rate												6.50%
Reduction In Indiana Corporate Tax Rate												0.50%
Indiana Corporate Tax Rate												4.90%
Original WV Corporate Income Tax Rate														7.00%
Reduced WV Corporate Income Tax														6.50%
Ohio Power Co [Member]
Federal:
Current												$ 178.8
Deferred												(40.8)
Deferred Investment Tax Credits													(0.1)	$ (0.3)
Total Federal												138
State and Local:
Current												4.2
Deferred												1.6
Deferred Investment Tax Credits													(0.1)	(0.3)
Total State and Local												5.8
Income Tax Expense (Credit)												143.8	126.5	132.2
Income Tax Expense:
Current													89	58.1
Deferred												(39.2)	37.6	74.4
Deferred Investment Tax Credits													(0.1)	(0.3)
Income Tax Expense (Credit)												143.8	126.5	132.2
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	37.5	99.9		74.6		70.2	48		71.6	47.7	65.4	282.2	232.7	216.4
Discontinued Operations				0			0		0	0	0
Income Tax Expense (Credit)												143.8	126.5	132.2
Pretax Income												426	359.2	348.6
Income Taxes on Pretax Income at Statutory Rate (35%)												149.1	125.7	122
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												7.1	8.2	6.7
Investment Tax Credits, Net												0	(0.1)	(0.2)
State and Local Income Taxes, Net												3.8	0.7	8.8
Other												(16.2)	(8)	(5.1)
Income Tax Expense (Credit)												$ 143.8	$ 126.5	$ 132.2
Effective Income Tax Rate												33.75587%	35.21715%	37.92312%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	232.4						162.4					$ 232.4	$ 162.4
Deferred Tax Liabilities	(1,578.5)						(1,545.6)					(1,578.5)	(1,545.6)
Property Related Temporary Differences	(1,090.8)						(1,022.8)					(1,090.8)	(1,022.8)
Amounts Due from Customers for Future Federal Income Taxes	(43.6)						(44.6)					(43.6)	(44.6)
Deferred State Income Taxes	(34.6)						(34.4)					(34.6)	(34.4)
Regulatory Assets	(174.1)						(220)					(174.1)	(220)
Deferred Income Taxes on Other Comprehensive Loss	(1.6)						(2.3)					(1.6)	(2.3)
Deferred Fuel and Purchased Power	(117.6)						(117.4)					(117.6)	(117.4)
All Other, Net	116.2						58.3					116.2	58.3
Net Deferred Tax Liabilities	(1,346.1)						(1,383.2)					(1,346.1)	(1,383.2)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0.2	1	$ 0.1
Interest Income												0	0	0
Reversal of Prior Period Interest Expense												0	0	0.2
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0						0					0	0
Accrual for Payment of Interest and Penalties	1.7						0.6					1.7	0.6
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,						6.9					6.9	6.9	6.9	2.1
Increase - Tax Positions Taken During a Prior Period												0	0	6.4
Decrease - Tax Positions Taken During a Prior Period												0	0	0
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Decrease - Settlements with Taxing Authorities												0	0	0
Decrease - Lapse of the Applicable Statute of Limitations												0	0	(1.6)
Balance at December 31,	6.9						6.9					6.9	6.9	6.9	2.1
Unrecognized Tax Benefits, if Recognized - Amount	4.4						4.5					$ 4.4	$ 4.5	$ 4.5
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Income Tax Expense (Credit)												$ 143.8	$ 126.5	$ 132.2
Net Income (Loss)	37.5	99.9		74.6		70.2	48		71.6	47.7	65.4	$ 282.2	232.7	$ 216.4
Period with No Change in Unrecognized Tax Benefits												12 months
Original Indiana Corporate Income Tax Rate												8.50%
Reduced Indiana Corporate Income Tax Rate												6.50%
Reduction In Indiana Corporate Tax Rate												0.50%
Indiana Corporate Tax Rate												4.90%
Original WV Corporate Income Tax Rate														7.00%
Reduced WV Corporate Income Tax														6.50%
Public Service Co Of Oklahoma [Member]
Federal:
Current												$ (28)
Deferred												77.2
Deferred Investment Tax Credits													(0.6)	$ 0.1
Total Federal												47.8
State and Local:
Current												(1.9)
Deferred												5.3
Deferred Investment Tax Credits													(0.6)	0.1
Total State and Local												6.6
Income Tax Expense (Credit)												54.4	51.3	50.6
Income Tax Expense:
Current													(6.4)	(24.2)
Deferred												82.5	58.3	74.7
Deferred Investment Tax Credits													(0.6)	0.1
Income Tax Expense (Credit)												54.4	51.3	50.6
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	2.6	52.8		28.9		15.7	7		44.7	27.1	13.7	100	92.5	86.9
Discontinued Operations				0			0		0	0	0
Income Tax Expense (Credit)												54.4	51.3	50.6
Pretax Income												154.4	143.8	137.5
Income Taxes on Pretax Income at Statutory Rate (35%)												54	50.3	48.1
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												0.8	0.5	0.2
Investment Tax Credits, Net												(1.4)	(1.8)	(0.8)
State and Local Income Taxes, Net												4.2	5.1	4.8
AFUDC												(2.2)	(3.1)	(1.1)
Other												(1)	0.3	(0.6)
Income Tax Expense (Credit)												$ 54.4	$ 51.3	$ 50.6
Effective Income Tax Rate												35.23316%	35.67455%	36.80%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	153.8						141.2					$ 153.8	$ 141.2
Deferred Tax Liabilities	(1,212.6)						(1,113)					(1,212.6)	(1,113)
Property Related Temporary Differences	(927.3)						(861.9)					(927.3)	(861.9)
Amounts Due from Customers for Future Federal Income Taxes	(3.2)						(2.2)					(3.2)	(2.2)
Deferred State Income Taxes	(128.5)						(117)					(128.5)	(117)
Regulatory Assets	(67.6)						(54.3)					(67.6)	(54.3)
Deferred Income Taxes on Other Comprehensive Loss	(1.8)						(2.3)					(1.8)	(2.3)
Deferred Federal Income Taxes on Deferred State Income Taxes	50.6						46.6					50.6	46.6
Net Operating Loss Carryforward	16.5						7.1					16.5	7.1
Tax Credit Carryforward	0						0.6					0	0.6
All Other, Net	2.5						11.6					2.5	11.6
Net Deferred Tax Liabilities	(1,058.8)						(971.8)					(1,058.8)	(971.8)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0	0.1	$ 0.1
Interest Income												0.3	0	0
Reversal of Prior Period Interest Expense												0.7	0	0.1
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0.6						0					0.6	0
Accrual for Payment of Interest and Penalties	0						0.4					0	0.4
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,						1.3					1.3	1.3	1.3	2.2
Increase - Tax Positions Taken During a Prior Period												0.1	0	0
Decrease - Tax Positions Taken During a Prior Period												(1.3)	0	0
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Decrease - Settlements with Taxing Authorities												0	0	0
Decrease - Lapse of the Applicable Statute of Limitations												0	0	(0.9)
Balance at December 31,	0.1						1.3					0.1	1.3	1.3	2.2
Unrecognized Tax Benefits, if Recognized - Amount	0.1						0.9					$ 0.1	$ 0.9	$ 0.9
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Federal Net Income Tax Operating Loss												$ 17
Income Tax Expense (Credit)												54.4	$ 51.3	$ 50.6
Net Income (Loss)	2.6	52.8		28.9		15.7	7		44.7	27.1	13.7	$ 100	92.5	86.9
Period with No Change in Unrecognized Tax Benefits												12 months
Pre-2016 TX Income/Franchise Tax Rate												0.95%
New TX Income/Franchise Tax Rate												0.75%
Anticipated TX Income/Franchise Tax Rate												1.00%
Transmission and Distribution Expenses Net Income Adjustment												$ 2
Southwestern Electric Power Co [Member]
Federal:
Current												(96.7)
Deferred												172.6
Deferred Investment Tax Credits													(1.4)	(1.4)
Total Federal												74.7
State and Local:
Current												(12.6)
Deferred												(10)
Deferred Investment Tax Credits													(1.4)	(1.4)
Total State and Local												(22.6)
Income Tax Expense (Credit)												52.1	84.8	66.4
Income Tax Expense:
Current													44.3	(171.6)
Deferred												162.6	41.9	239.4
Deferred Investment Tax Credits													(1.4)	(1.4)
Income Tax Expense (Credit)												52.1	84.8	66.4
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Net Income	16.5	84.4		44.3		24.5	7.7		82.1	59.5	46.7	169.7	196	144.6
Discontinued Operations				0			0		0	0	0
Income Tax Expense (Credit)												52.1	84.8	66.4
Pretax Income												221.8	280.8	211
Income Taxes on Pretax Income at Statutory Rate (35%)												77.6	98.3	73.8
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Depreciation												3.2	3.1	2.9
Depletion												(5.5)	(5.5)	(4.1)
Investment Tax Credits, Net												(1.2)	(1.4)	(1.4)
State and Local Income Taxes, Net												(14.7)	4.8	3.1
AFUDC												(3.9)	(9.2)	(4.2)
Other												(3.4)	(5.3)	(3.7)
Income Tax Expense (Credit)												$ 52.1	$ 84.8	$ 66.4
Effective Income Tax Rate												23.48963%	30.19943%	31.46919%
Net Deferred Tax Liability and Significant Temporary Differences
Deferred Tax Assets	230.5						194.7					$ 230.5	$ 194.7
Deferred Tax Liabilities	(1,837.4)						(1,594.5)					(1,837.4)	(1,594.5)
Property Related Temporary Differences	(1,445.2)						(1,275.1)					(1,445.2)	(1,275.1)
Amounts Due from Customers for Future Federal Income Taxes	(48.2)						(47.8)					(48.2)	(47.8)
Deferred State Income Taxes	(175.1)						(132.3)					(175.1)	(132.3)
Regulatory Assets	(40.7)						(26.1)					(40.7)	(26.1)
Deferred Income Taxes on Other Comprehensive Loss	5.1						5					5.1	5
Impairment Loss	20.3						20.7					20.3	20.7
Net Operating Loss Carryforward	40.3						19.7					40.3	19.7
Tax Credit Carryforward	0.1						0.7					0.1	0.7
All Other, Net	36.5						35.4					36.5	35.4
Net Deferred Tax Liabilities	(1,606.9)						(1,399.8)					(1,606.9)	(1,399.8)
Summary of Amounts Reported for Interest Expense, Interest Income and Reversal of Prior Period Interest Expense
Interest Expense												0	0.4	$ 0.2
Interest Income												0	0	0
Reversal of Prior Period Interest Expense												1.4	0	0.2
Amounts Accrued for Receipt of Interest and Payment of Interest and Penalties
Accrual for Receipt of Interest	0.1						0					0.1	0
Accrual for Payment of Interest and Penalties	0						1.4					0	1.4
Reconciliation of the Beginning and Ending Amount of Unrecognized Tax Benefits
Balance at January 1,						9.3					7.5	9.3	7.5	7.6
Increase - Tax Positions Taken During a Prior Period												1.3	1.8	1.6
Decrease - Tax Positions Taken During a Prior Period												(9.3)	0	(0.8)
Increase - Tax Positions Taken During the Current Year												0	0	0
Decrease - Tax Positions Taken During the Current Year												0	0	0
Decrease - Settlements with Taxing Authorities												0	0	0
Decrease - Lapse of the Applicable Statute of Limitations												0	0	(0.9)
Balance at December 31,	1.3						9.3					1.3	9.3	7.5	7.6
Unrecognized Tax Benefits, if Recognized - Amount	0.8						6					$ 0.8	$ 6	$ 4.9
Income Taxes (Textuals) [Abstract]
Statutory Tax Rate on Pretax Income												35.00%	35.00%	35.00%
Federal Net Income Tax Operating Loss												$ 37
Income Tax Expense (Credit)												52.1	$ 84.8	$ 66.4
Net Income (Loss)	16.5	$ 84.4		$ 44.3		$ 24.5	7.7		$ 82.1	$ 59.5	$ 46.7	$ 169.7	196	144.6
Period with No Change in Unrecognized Tax Benefits												12 months
Pre-2016 TX Income/Franchise Tax Rate												0.95%
New TX Income/Franchise Tax Rate												0.75%
Anticipated TX Income/Franchise Tax Rate												1.00%
Transmission and Distribution Expenses Net Income Adjustment												$ 9
Arkansas [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	16.7											$ 16.7
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2021
Arkansas [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	16.2											$ 16.2
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2021
Kentucky [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	89.7											$ 89.7
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Louisiana [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	509.1											$ 509.1
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Louisiana [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	508.3											$ 508.3
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Missouri [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	6.3											$ 6.3
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Oklahoma [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	529.9											$ 529.9
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Oklahoma [Member] | Public Service Co Of Oklahoma [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	273.2											$ 273.2
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Oklahoma [Member] | Southwestern Electric Power Co [Member]
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	4.2											$ 4.2
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Federal [Member]
Federal:
Deferred Investment Tax Credits												$ 17.6
State and Local:
Deferred Investment Tax Credits												17.6
Income Tax Expense:
Deferred Investment Tax Credits												17.6
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	50											$ 50
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount	53.6											$ 53.6
Tax Credit Carryforward Amount To Expire If Not Used	34.3											34.3
Income Taxes (Textuals) [Abstract]
Uncertain Tax Positions Netted Against Operating Loss Carryforward															121
Uncertain Tax Position Noncurrent														$ 69
Uncertain Tax Positions Netted Against Tax Credit and Alternative Minimum Tax Carryforward Tax Benefits	17						59					$ 17	$ 59
Federal [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2036
Federal [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2032
Federal [Member] | Appalachian Power Co [Member]
Federal:
Deferred Investment Tax Credits												$ (0.1)
State and Local:
Deferred Investment Tax Credits												(0.1)
Income Tax Expense:
Deferred Investment Tax Credits												(0.1)
Tax Credit Carryforward
Tax Credit Carryforward, Amount	11.7											11.7
Tax Credit Carryforward Amount To Expire If Not Used	4.5											$ 4.5
Federal [Member] | Appalachian Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2036
Federal [Member] | Appalachian Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2032
Federal [Member] | Indiana Michigan Power Co [Member]
Federal:
Deferred Investment Tax Credits												$ 3.8
State and Local:
Deferred Investment Tax Credits												3.8
Income Tax Expense:
Deferred Investment Tax Credits												3.8
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	7											$ 7
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount	9											$ 9
Tax Credit Carryforward Amount To Expire If Not Used	8.5											$ 8.5
Federal [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2036
Federal [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2032
Federal [Member] | Ohio Power Co [Member]
Federal:
Deferred Investment Tax Credits												$ 0
State and Local:
Deferred Investment Tax Credits												0
Income Tax Expense:
Deferred Investment Tax Credits												0
Tax Credit Carryforward
Tax Credit Carryforward, Amount	8.6											8.6
Tax Credit Carryforward Amount To Expire If Not Used	0											$ 0
Federal [Member] | Ohio Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2036
Federal [Member] | Ohio Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2032
Federal [Member] | Public Service Co Of Oklahoma [Member]
Federal:
Deferred Investment Tax Credits												$ (1.4)
State and Local:
Deferred Investment Tax Credits												(1.4)
Income Tax Expense:
Deferred Investment Tax Credits												(1.4)
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	6											$ 6
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											$ 0
Tax Credit Carryforward Amount To Expire If Not Used	0											$ 0
Federal [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2036
Federal [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2032
Federal [Member] | Southwestern Electric Power Co [Member]
Federal:
Deferred Investment Tax Credits												$ (1.2)
State and Local:
Deferred Investment Tax Credits												(1.2)
Income Tax Expense:
Deferred Investment Tax Credits												(1.2)
Net Income Tax Operating Loss Carryforwards
Net Income Tax Operating Loss Carryforward	13											$ 13
Operating Loss Carryforwards, Expiration Date												Dec. 31, 2036
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0.1											$ 0.1
Tax Credit Carryforward Amount To Expire If Not Used	0											$ 0
Federal [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Dec. 31, 2036
Federal [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Income Taxes (Textuals) [Abstract]
Tax Credit Carryforward, Expiration Date												Jan. 1, 2032
State [Member]
Federal:
Deferred Investment Tax Credits												$ (0.1)
State and Local:
Deferred Investment Tax Credits												(0.1)
Income Tax Expense:
Deferred Investment Tax Credits												(0.1)
Tax Credit Carryforward
Tax Credit Carryforward, Amount	26.6											26.6
Tax Credit Carryforward Amount To Expire If Not Used	26.6											26.6
State [Member] | Appalachian Power Co [Member]
Federal:
Deferred Investment Tax Credits												0
State and Local:
Deferred Investment Tax Credits												0
Income Tax Expense:
Deferred Investment Tax Credits												0
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											0
Tax Credit Carryforward Amount To Expire If Not Used	0											0
State [Member] | Indiana Michigan Power Co [Member]
Federal:
Deferred Investment Tax Credits												0
State and Local:
Deferred Investment Tax Credits												0
Income Tax Expense:
Deferred Investment Tax Credits												0
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											0
Tax Credit Carryforward Amount To Expire If Not Used	0											0
State [Member] | Ohio Power Co [Member]
Federal:
Deferred Investment Tax Credits												0
State and Local:
Deferred Investment Tax Credits												0
Income Tax Expense:
Deferred Investment Tax Credits												0
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											0
Tax Credit Carryforward Amount To Expire If Not Used	0											0
State [Member] | Public Service Co Of Oklahoma [Member]
Federal:
Deferred Investment Tax Credits												3.2
State and Local:
Deferred Investment Tax Credits												3.2
Income Tax Expense:
Deferred Investment Tax Credits												3.2
Tax Credit Carryforward
Tax Credit Carryforward, Amount	26.6											26.6
Tax Credit Carryforward Amount To Expire If Not Used	26.6											26.6
State [Member] | Southwestern Electric Power Co [Member]
Federal:
Deferred Investment Tax Credits												0
State and Local:
Deferred Investment Tax Credits												0
Income Tax Expense:
Deferred Investment Tax Credits												0
Tax Credit Carryforward
Tax Credit Carryforward, Amount	0											0
Tax Credit Carryforward Amount To Expire If Not Used	0											0
Uk Windfall Tax Issue [Member]
State and Local:
Income Tax Expense (Credit)															80
Income Tax Expense:
Income Tax Expense (Credit)															80
Reconciliation of Federal Income Taxes and Amount of Income Tax Reported
Income Tax Expense (Credit)															80
Reconciliation of Federal Statutory Rate and Amount of Taxes Reported
Income Tax Expense (Credit)															80
Income Taxes (Textuals) [Abstract]
Income Tax Expense (Credit)															80
Interest Income															$ 43
Tax Increase Prevention Act of 2014 [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
Tax Increase Prevention Act of 2014 [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
Tax Increase Prevention Act of 2014 [Member] | Indiana Michigan Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
Tax Increase Prevention Act of 2014 [Member] | Ohio Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
Tax Increase Prevention Act of 2014 [Member] | Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
Tax Increase Prevention Act of 2014 [Member] | Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension														50.00%
Protecting Americans from Tax Hikes Act of 2015 [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension													50.00%
Bonus Depreciation Extension Phase Down 40													40.00%
Bonus Depreciation Extension Phase Down 30													30.00%
Solar Investment Tax Credit													30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Appalachian Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension													50.00%
Bonus Depreciation Extension Phase Down 40													40.00%
Bonus Depreciation Extension Phase Down 30													30.00%
Solar Investment Tax Credit													30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Indiana Michigan Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension													50.00%
Bonus Depreciation Extension Phase Down 40													40.00%
Bonus Depreciation Extension Phase Down 30													30.00%
Solar Investment Tax Credit													30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Ohio Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension													50.00%
Bonus Depreciation Extension Phase Down 40													40.00%
Bonus Depreciation Extension Phase Down 30													30.00%
Solar Investment Tax Credit													30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension													50.00%
Bonus Depreciation Extension Phase Down 40													40.00%
Bonus Depreciation Extension Phase Down 30													30.00%
Solar Investment Tax Credit													30.00%
Protecting Americans from Tax Hikes Act of 2015 [Member] | Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Bonus Depreciation Extension													50.00%
Bonus Depreciation Extension Phase Down 40													40.00%
Bonus Depreciation Extension Phase Down 30													30.00%
Solar Investment Tax Credit													30.00%
Net Tax Benefit [Member]
Income Taxes (Textuals) [Abstract]
Discontinued Operations												0	$ 6.2	$ 39
Expiration of Charitable Contribution Carryforward Deductions [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance	(6)						(17)					(6)	(17)
Income Taxes (Textuals) [Abstract]
Valuation Allowance	(6)						(17)					(6)	(17)
Investment in Operations of AEPRO [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance							(156)						(156)
Income Taxes (Textuals) [Abstract]
Valuation Allowance							(156)						(156)
Sale of AEPRO [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance							(48)						(48)
Income Taxes (Textuals) [Abstract]
Valuation Allowance							$ (48)						$ (48)
2011 Audit Issue Settlement [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance	(56)											(56)
Income Taxes (Textuals) [Abstract]
Valuation Allowance	(56)											(56)
Certain Assets Held for Sale and 2015 Federal Income Tax Return [Member]
Net Deferred Tax Liability and Significant Temporary Differences
Valuation Allowance	(66)											(66)
Income Taxes (Textuals) [Abstract]
Valuation Allowance	$ (66)											$ (66)
[1]	Includes impairments for Merchant Generating Assets (see Note 7).
[2]	Includes final accounting adjustment for sale of AEPRO (see Note 7).
[3]	Includes sale of AEPRO (see Note 7).

Leases (Details)

Leases (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Lease Rental Costs
Net Lease Expense on Operating Leases		$ 224.9	$ 292.6		$ 303.9
Amortization of Capital Leases		93.7	108.5		109.4
Interest on Capital Leases		18.9	25.1		26.1
Total Lease Rental Costs		337.5	426.2	[1]	439.4	[1]
Lease Expenses Related to AEPRO			89		96
PP&E and Related Obligations Under Capital Leases
Generation		146.3	128.2
Other Property, Plant and Equipment		373.1	439.3
Total Property, Plant and Equipment Under Capital Leases		519.4	567.5
Accumulated Amortization		226.4	214.1
Net Property, Plant and Equipment Under Capital Leases		293	353.4
Noncurrent Liability		242.1	247.3
Liability Due Within One Year		63.4	96.2
Total Obligations Under Capital Leases		305.5	343.5
Future Minimum Lease Payments
Capital Leases, 2017		81.3
Noncancelable Operating Leases, 2017		238.2
Capital Leases, 2018		65
Noncancelable Operating Leases, 2018		229.5
Capital Leases, 2019		48.7
Noncancelable Operating Leases, 2019		221
Capital Leases, 2020		39.3
Noncancelable Operating Leases, 2020		212.7
Capital Leases, 2021		32.8
Noncancelable Operating Leases, 2021		197.6
Capital Leases, Later Years		118.7
Noncancelable Operating Leases, Later Years		282.2
Capital Leases, Total Future Minimum Lease Payments		385.8
Noncancelable Operating Leases, Total Future Minimum Lease Payments		1,381.2
Less Estimated Interest Element on Capital Leases		80.3
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		305.5
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		$ 36.7
Leases (Textuals) [Abstract]
Maximum Remaining Lease Term		15 years
Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,017	[2]	$ 147.8
2,018	[2]	147.8
2,019	[2]	147.8
2,020	[2]	147.8
2,021	[2]	147.8
Later Years	[2]	147.2
Total Future Minimum Lease Payments	[2]	$ 886.2
Leases (Textuals) [Abstract]
Lease Term		33 years
Nuclear Fuel Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,017		$ 5.8
2,018		2.4
Total Future Minimum Lease Payments		$ 8.2
Leases (Textuals) [Abstract]
Lease Term		54 months
Portion of Unamortized Nuclear Fuel Inventory Sold at Cost		$ 110
Railcar Lease [Member]
Leases (Textuals) [Abstract]
Sale Proceeds Guaranteed by Lessor Under Current Five Year Lease Term		83.00%
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Boat and Barge Leases [Member]
Leases (Textuals) [Abstract]
Maximum Potential Lease Payments, AEPRO Barge and Boat Leases		$ 85
Guarantor Obligations, Current Carrying Value		13
GuaranteeObligationsCurrentCarryingValueOtherLiabilitiesCurrent		2
GuaranteeObligationsCurrentCarryingValueOtherLiabilitiesNoncurrent		11
Sabine Dragline Lease [Member]
Leases (Textuals) [Abstract]
Cost of Electric Draglines to be Used for Mining Operations		47
Appalachian Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		16.6	16.4		18.3
Amortization of Capital Leases		6.4	5.6		5.5
Interest on Capital Leases		3.5	0.8		1
Total Lease Rental Costs		26.5	22.8		24.8
PP&E and Related Obligations Under Capital Leases
Generation		45	43.4
Other Property, Plant and Equipment		18.1	17.6
Total Property, Plant and Equipment Under Capital Leases		63.1	61
Accumulated Amortization		18.1	15.6
Net Property, Plant and Equipment Under Capital Leases		45	45.4
Noncurrent Liability		38.2	39.1
Liability Due Within One Year		6.8	6.3
Total Obligations Under Capital Leases		45	45.4
Future Minimum Lease Payments
Capital Leases, 2017		10.3
Noncancelable Operating Leases, 2017		16.2
Capital Leases, 2018		9.3
Noncancelable Operating Leases, 2018		14.9
Capital Leases, 2019		7.3
Noncancelable Operating Leases, 2019		13.5
Capital Leases, 2020		6.5
Noncancelable Operating Leases, 2020		12.9
Capital Leases, 2021		6.2
Noncancelable Operating Leases, 2021		10.5
Capital Leases, Later Years		23.7
Noncancelable Operating Leases, Later Years		29
Capital Leases, Total Future Minimum Lease Payments		63.3
Noncancelable Operating Leases, Total Future Minimum Lease Payments		97
Less Estimated Interest Element on Capital Leases		18.3
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		45
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		5.4
Indiana Michigan Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		90.5	88.3		93.4
Amortization of Capital Leases		35.6	40.7		44.4
Interest on Capital Leases		3.7	3.3		2.8
Total Lease Rental Costs		129.8	132.3		140.6
PP&E and Related Obligations Under Capital Leases
Generation		26.4	14.5
Other Property, Plant and Equipment		43.7	68.2
Total Property, Plant and Equipment Under Capital Leases		70.1	82.7
Accumulated Amortization		25.4	19.7
Net Property, Plant and Equipment Under Capital Leases		44.7	63
Noncurrent Liability		35.3	30.2
Liability Due Within One Year		9.4	32.8
Total Obligations Under Capital Leases		44.7	63
Future Minimum Lease Payments
Capital Leases, 2017		15.2
Noncancelable Operating Leases, 2017		91.8
Capital Leases, 2018		9.5
Noncancelable Operating Leases, 2018		90.6
Capital Leases, 2019		5.8
Noncancelable Operating Leases, 2019		89.5
Capital Leases, 2020		5.3
Noncancelable Operating Leases, 2020		86
Capital Leases, 2021		5
Noncancelable Operating Leases, 2021		81.6
Capital Leases, Later Years		27.6
Noncancelable Operating Leases, Later Years		94.6
Capital Leases, Total Future Minimum Lease Payments		68.4
Noncancelable Operating Leases, Total Future Minimum Lease Payments		534.1
Less Estimated Interest Element on Capital Leases		23.7
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		44.7
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.4
Indiana Michigan Power Co [Member] | Rockport Lease [Member]
Future Minimum Rentals, Sale Leaseback Transactions
2,017		73.9
2,018		73.9
2,019		73.9
2,020		73.9
2,021		73.9
Later Years		73.6
Total Future Minimum Lease Payments		$ 443.1
Leases (Textuals) [Abstract]
Lease Term		33 years
Indiana Michigan Power Co [Member] | Railcar Lease [Member]
Leases (Textuals) [Abstract]
Future Minimum Lease Obligation for Remaining Railcars		$ 9
Sale Proceeds Guaranteed by Lessor Under Current Five Year Lease Term		83.00%
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Maximum Potential Loss Related to Guarantee		$ 8
Ohio Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		7.1	7.6		6.6
Amortization of Capital Leases		4.2	3.9		5.7
Interest on Capital Leases		0.5	0.6		1.2
Total Lease Rental Costs		11.8	12.1		13.5
PP&E and Related Obligations Under Capital Leases
Generation		0	0
Other Property, Plant and Equipment		23.9	23.4
Total Property, Plant and Equipment Under Capital Leases		23.9	23.4
Accumulated Amortization		11.6	10.2
Net Property, Plant and Equipment Under Capital Leases		12.3	13.2
Noncurrent Liability		8.1	9.3
Liability Due Within One Year		4.2	3.9
Total Obligations Under Capital Leases		12.3	13.2
Future Minimum Lease Payments
Capital Leases, 2017		4.7
Noncancelable Operating Leases, 2017		9.3
Capital Leases, 2018		3.8
Noncancelable Operating Leases, 2018		7.9
Capital Leases, 2019		1.5
Noncancelable Operating Leases, 2019		6.4
Capital Leases, 2020		1.1
Noncancelable Operating Leases, 2020		5.4
Capital Leases, 2021		0.9
Noncancelable Operating Leases, 2021		4.5
Capital Leases, Later Years		1.5
Noncancelable Operating Leases, Later Years		18.3
Capital Leases, Total Future Minimum Lease Payments		13.5
Noncancelable Operating Leases, Total Future Minimum Lease Payments		51.8
Less Estimated Interest Element on Capital Leases		1.2
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		12.3
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		5.8
Public Service Co Of Oklahoma [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		5	5.4		3.2
Amortization of Capital Leases		3.7	3.5		4.2
Interest on Capital Leases		0.6	0.7		0.7
Total Lease Rental Costs		9.3	9.6		8.1
PP&E and Related Obligations Under Capital Leases
Generation		10	9.6
Other Property, Plant and Equipment		19.4	18.6
Total Property, Plant and Equipment Under Capital Leases		29.4	28.2
Accumulated Amortization		15.6	13.6
Net Property, Plant and Equipment Under Capital Leases		13.8	14.6
Noncurrent Liability		9.8	10.9
Liability Due Within One Year		4.1	3.7
Total Obligations Under Capital Leases		13.9	14.6
Future Minimum Lease Payments
Capital Leases, 2017		4.7
Noncancelable Operating Leases, 2017		4.4
Capital Leases, 2018		3.4
Noncancelable Operating Leases, 2018		3.9
Capital Leases, 2019		2.1
Noncancelable Operating Leases, 2019		3.4
Capital Leases, 2020		1.5
Noncancelable Operating Leases, 2020		2.9
Capital Leases, 2021		1.1
Noncancelable Operating Leases, 2021		1.9
Capital Leases, Later Years		2.6
Noncancelable Operating Leases, Later Years		4.6
Capital Leases, Total Future Minimum Lease Payments		15.4
Noncancelable Operating Leases, Total Future Minimum Lease Payments		21.1
Less Estimated Interest Element on Capital Leases		1.5
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		13.9
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3
Southwestern Electric Power Co [Member]
Lease Rental Costs
Net Lease Expense on Operating Leases		6.7	6.7		5.5
Amortization of Capital Leases		13.6	13.7		14.9
Interest on Capital Leases		5.1	6.2		7.4
Total Lease Rental Costs		25.4	26.6		$ 27.8
PP&E and Related Obligations Under Capital Leases
Generation		34.5	34.5
Other Property, Plant and Equipment		122.1	165.1
Total Property, Plant and Equipment Under Capital Leases		156.6	199.6
Accumulated Amortization		86.5	91.3
Net Property, Plant and Equipment Under Capital Leases		70.1	108.3
Noncurrent Liability		65.5	75.6
Liability Due Within One Year		11.8	21.9
Total Obligations Under Capital Leases		77.3	$ 97.5
Future Minimum Lease Payments
Capital Leases, 2017		14.7
Noncancelable Operating Leases, 2017		6.1
Capital Leases, 2018		13.7
Noncancelable Operating Leases, 2018		5.7
Capital Leases, 2019		12.2
Noncancelable Operating Leases, 2019		5.4
Capital Leases, 2020		10.4
Noncancelable Operating Leases, 2020		5.1
Capital Leases, 2021		9.6
Noncancelable Operating Leases, 2021		4.6
Capital Leases, Later Years		33.1
Noncancelable Operating Leases, Later Years		15
Capital Leases, Total Future Minimum Lease Payments		93.7
Noncancelable Operating Leases, Total Future Minimum Lease Payments		41.9
Less Estimated Interest Element on Capital Leases		16.4
Estimated Present Value of Future Minimum Lease Payments on Capital Leases		77.3
Maximum Potential Loss
Max Potential Loss on Master Lease Agreements		3.5
Southwestern Electric Power Co [Member] | Railcar Lease [Member]
Leases (Textuals) [Abstract]
Future Minimum Lease Obligation for Remaining Railcars		$ 10
Sale Proceeds Guaranteed by Lessor Under Current Five Year Lease Term		83.00%
Sale Proceeds Guaranteed by Lessor at the End of 20-Year Term		77.00%
Maximum Potential Loss Related to Guarantee		$ 10
[1]	Amounts include lease expenses related to AEPRO that have been classified as Other Operation Expense from Discontinued Operations on the statements of income in the amounts of $89 million and $96 million for the Years Ended December 31, 2015 and 2014, respectively. See “AEPRO (Corporate and Other)” section of Note 7 for additional information.
[2]	AEP’s future minimum lease payments includes equal shares from AEGCo and I&M.

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Thousands		1 Months Ended		12 Months Ended
		Feb. 27, 2017	Jan. 31, 2017	Dec. 31, 2016	Dec. 31, 2015		Dec. 31, 2014
Shares of Company
Beginning Balance, Shares			512,048,520	511,389,173	509,739,159		508,113,964
Issued				659,347	1,650,014		1,625,195
Ending Balance, Shares				512,048,520	511,389,173		509,739,159
Treasury Stock, Shares, Beginning Balance			20,336,592	20,336,592	20,336,592		20,336,592
Treasury Stock, Shares, Ending Balance				20,336,592	20,336,592		20,336,592
Long-term Debt
Senior Unsecured Notes					$ 13,629,100
Pollution Control Bonds	[1]			$ 1,725,100	1,784,800
Notes Payable	[2]			326,900	264,700	[3]
Securitization Bonds				1,705,000	2,024,000
Spent Nuclear Fuel Obligation	[4]			266,300	265,600
Other Long-term Debt				1,606,900	1,604,500
Total Long-term Debt Outstanding				20,256,400	19,572,700	[3]
Outstanding Long-term Debt
Principal Amount, 2018				1,987,000
Principal Amount, 2019				2,287,100
Principal Amount, 2020				486,400
Principal Amount, 2021				1,308,400
Principal Amount, After 2021				11,437,300
Total Long-term Debt Outstanding				20,256,400	19,572,700	[3]
Short-term Debt
Securitized Debt for Receivables	[5]			673,000	675,000
Commercial Paper				1,040,000	125,000
Total Short-term Debt				$ 1,713,000	$ 800,000
Securitized Debt for Receivables	[6]			0.7002%	0.30%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable				0.70%	0.30%		0.22%
Net Uncollectible Accounts Receivable Written Off				$ 23,700	$ 34,100		$ 40,100
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts				945,000	924,800
Total Principal Outstanding				673,000	675,000
Delinquent Securitized Accounts Receivable				42,700	48,300
Bad Debt Reserves Related to Securitized Sale of Accounts Receivable				27,700	17,500
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable				322,100	357,800
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				1,794,900	2,397,900		1,777,400
Total Commitment From Bank Conduits To Finance Receivables				750,000	700,000
Reaquired Pollution Control Bonds Held by Trustees				$ 614,000
Maximum Percentage Debt to Capitalization				67.50%
Restricted Net Assets				$ 10,900,000
Retained Earnings Available to Pay Dividends				6,400,000
Dividend Restrictions				1,534,900
Dividends Paid on Common Stock				(1,121,000)	$ (1,059,000)		(997,600)
Credit Facilities, Total				3,500,000
Maximum Amount of Commercial Paper Outstanding				$ 1,500,000
Weighted Average Interest Rate of Commercial Paper Outstanding During Year				0.80053%
Commercial Paper [Member]
Short-term Debt
Commercial Paper	[6]			1.0155%	0.81%
Appalachian Power Co [Member]
Long-term Debt
Senior Unsecured Notes				$ 2,972,400	$ 2,970,400
Pollution Control Bonds	[1]			615,800	616,500
Securitization Bonds				318,900	341,500
Other Long-term Debt				126,800	2,300
Total Long-term Debt Outstanding				4,033,900	3,930,700
Outstanding Long-term Debt
Principal Amount, 2017				503,100
Principal Amount, 2018				194,000
Principal Amount, 2019				235,500
Principal Amount, 2020				140,300
Principal Amount, 2021				393,000
Principal Amount, After 2021				2,602,000
Principal Amount, Total				4,067,900
Unamortized Discount, Net and Debt Issuance Costs				(34,000)
Total Long-term Debt Outstanding				4,033,900	3,930,700
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				142,000	135,400
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				6,700	7,600		8,900
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,412,500	1,453,800		1,519,300
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				$ 213,600	672,600		$ 612,700
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 0
Appalachian Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				286,900	211,200
Maximum Loans to Money Pool				25,700	694,800
Average Borrowings from Money Pool				148,000	82,000
Average Loans to Money Pool				24,800	79,000
Net Loans (Borrowings) to/from Money Pool				(55,500)	(155,400)
Authorized Short Term Borrowing Limit				$ 600,000	$ 600,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.02%	0.87%		0.59%
Minimum Interest Rate				0.69%	0.37%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.80%	0.53%		0.29%
Average Interest Rate For Funds Loaned				0.82%	0.47%		0.29%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 1,200	$ 200		$ 0
Interest Income
Interest Income Earned On Advances To Money Pool				200	400		300
Indiana Michigan Power Co [Member]
Long-term Debt
Senior Unsecured Notes				1,512,800	1,117,000
Pollution Control Bonds	[1]			225,400	225,100
Notes Payable	[2]			251,400	175,500
Spent Nuclear Fuel Obligation	[4]			266,300	265,600
Other Long-term Debt				215,500	216,800
Total Long-term Debt Outstanding				2,471,400	2,000,000
Outstanding Long-term Debt
Principal Amount, 2017				209,300
Principal Amount, 2018				369,300
Principal Amount, 2019				518,800
Principal Amount, 2020				10,500
Principal Amount, 2021				3,900
Principal Amount, After 2021				1,373,700
Principal Amount, Total				2,485,500
Unamortized Discount, Net and Debt Issuance Costs				(14,100)
Total Long-term Debt Outstanding				2,471,400	2,000,000
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				136,700	134,800
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				7,100	8,400		7,900
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,596,200	1,553,000		1,488,600
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				100,200	332,100		$ 218,500
Reaquired Pollution Control Bonds Held by Trustees				$ 40,000
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 288,500
Indiana Michigan Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				369,100	297,300
Maximum Loans to Money Pool				97,600	13,500
Average Borrowings from Money Pool				129,900	152,600
Average Loans to Money Pool				19,500	13,500
Net Loans (Borrowings) to/from Money Pool				(202,700)	(282,600)
Authorized Short Term Borrowing Limit				$ 500,000	$ 500,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.02%	0.87%		0.59%
Minimum Interest Rate				0.69%	0.37%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.80%	0.49%		0.31%
Average Interest Rate For Funds Loaned				0.80%	0.48%		0.30%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 900	$ 800		$ 100
Interest Income
Interest Income Earned On Advances To Money Pool				200	100		100
Ohio Power Co [Member]
Long-term Debt
Senior Unsecured Notes				1,590,200	1,938,900
Pollution Control Bonds	[1]			32,300	32,200
Securitization Bonds				140,200	185,300
Other Long-term Debt				1,200	1,300
Total Long-term Debt Outstanding				1,763,900	2,157,700
Outstanding Long-term Debt
Principal Amount, 2017				46,400
Principal Amount, 2018				397,000
Principal Amount, 2019				48,000
Principal Amount, 2020				100
Principal Amount, 2021				500,100
Principal Amount, After 2021				783,000
Principal Amount, Total				1,774,600
Unamortized Discount, Net and Debt Issuance Costs				(10,700)
Total Long-term Debt Outstanding				1,763,900	2,157,700
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				388,300	351,400
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				28,900	30,700		28,800
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				2,633,000	2,569,400		2,647,600
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				395,900	131,500		$ 438,600
Reaquired Pollution Control Bonds Held by Trustees				345,000
Dividend Restrictions				0
Ohio Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				227,900	0
Maximum Loans to Money Pool				379,200	367,500
Average Borrowings from Money Pool				116,600	0
Average Loans to Money Pool				182,400	266,600
Net Loans (Borrowings) to/from Money Pool				24,200	331,100
Authorized Short Term Borrowing Limit				$ 400,000	$ 400,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.02%	0.87%		0.59%
Minimum Interest Rate				0.69%	0.37%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.85%	0.00%		0.27%
Average Interest Rate For Funds Loaned				0.74%	0.48%		0.34%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 400	$ 0		$ 0
Interest Income
Interest Income Earned On Advances To Money Pool				$ 900	$ 1,300		200
Public Service Co Of Oklahoma [Member]
Shares of Company
Beginning Balance, Shares			10,482,000	10,482,000
Ending Balance, Shares				10,482,000	10,482,000
Long-term Debt
Senior Unsecured Notes				$ 1,143,200	$ 1,142,700
Pollution Control Bonds	[1]			12,600	12,600
Other Long-term Debt				130,200	130,800
Total Long-term Debt Outstanding				1,286,000	1,286,100
Outstanding Long-term Debt
Principal Amount, 2017				500
Principal Amount, 2018				500
Principal Amount, 2019				375,400
Principal Amount, 2020				13,200
Principal Amount, 2021				250,500
Principal Amount, After 2021				653,000
Principal Amount, Total				1,293,100
Unamortized Discount, Net and Debt Issuance Costs				(7,100)
Total Long-term Debt Outstanding				1,286,000	1,286,100
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				110,400	116,100
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				6,200	5,800		5,900
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,269,300	1,326,100		1,321,100
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				$ 275,400	400		$ 34,100
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 127,500
Public Service Co Of Oklahoma [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				52,000	165,900
Maximum Loans to Money Pool				205,400	152,500
Average Borrowings from Money Pool				12,900	113,100
Average Loans to Money Pool				48,100	86,800
Net Loans (Borrowings) to/from Money Pool				(52,000)	80,600
Authorized Short Term Borrowing Limit				$ 300,000	$ 300,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.02%	0.87%		0.59%
Minimum Interest Rate				0.69%	0.37%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.96%	0.49%		0.29%
Average Interest Rate For Funds Loaned				0.83%	0.48%		0.00%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 0	$ 100		$ 300
Interest Income
Interest Income Earned On Advances To Money Pool				400	400		0
Southwestern Electric Power Co [Member]
Long-term Debt
Senior Unsecured Notes				2,359,200	1,961,000
Pollution Control Bonds	[1]			134,900	134,500
Notes Payable	[2]			75,300	78,600
Other Long-term Debt				109,700	99,400
Total Long-term Debt Outstanding				2,679,100	2,273,500
Outstanding Long-term Debt
Principal Amount, 2017				353,700
Principal Amount, 2018				385,400
Principal Amount, 2019				457,200
Principal Amount, 2020				3,700
Principal Amount, 2021				3,700
Principal Amount, After 2021				1,491,900
Principal Amount, Total				2,695,600
Unamortized Discount, Net and Debt Issuance Costs				(16,500)
Total Long-term Debt Outstanding				2,679,100	2,273,500
Accounts Receivable and Accrued Unbilled Revenue
Accounts Receivable and Accrued Unbilled Revenues				130,900	151,800
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold				6,900	7,000		6,800
Proceeds on Sale of Receivables to AEP Credit
Proceeds from Sale of Receivables to AEP Credit				1,531,700	1,597,800		1,655,800
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt				$ 3,300	306,800		3,300
Maximum Percentage Debt to Capitalization				67.50%
Dividend Restrictions				$ 528,900
Dividends Paid on Common Stock				(4,200)	(3,600)		$ (4,300)
Southwestern Electric Power Co [Member] | Utility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Money Pool				249,400	112,500
Maximum Loans to Money Pool				313,300	299,900
Average Borrowings from Money Pool				171,800	48,100
Average Loans to Money Pool				267,700	103,400
Net Loans (Borrowings) to/from Money Pool				167,800	(58,300)
Authorized Short Term Borrowing Limit				$ 350,000	$ 350,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.02%	0.87%		0.59%
Minimum Interest Rate				0.69%	0.37%		0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Borrowed				0.79%	0.53%		0.29%
Average Interest Rate For Funds Loaned				0.90%	0.48%		0.32%
Interest Expense
Interest Expense Incurred on Borrowings from the Money Pool				$ 1,000	$ 100		$ 200
Interest Income
Interest Income Earned On Advances To Money Pool				600	$ 400		$ 0
Southwestern Electric Power Co [Member] | Nonutility [Member]
Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Loans to Money Pool				2,000
Average Loans to Money Pool				2,000
Net Loans (Borrowings) to/from Money Pool				$ 2,000
Maximum and Minimum Interest Rates
Maximum Interest Rate				1.02%
Minimum Interest Rate				0.69%
Average Interest Rates for Funds Borrowed from and Loaned to Money Pool
Average Interest Rate For Funds Loaned				0.82%
Interest Income
Interest Income Earned On Advances To Money Pool				$ 16
Non-Registrant AEP Subsidiaries [Member]
Financing Activities (Textuals) [Abstract]
Dividend Restrictions				$ 590,000
Senior Notes [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,046
Weighted Average Interest Rate				4.90%
Senior Notes [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.65%	1.65%
Senior Notes [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				8.13%	8.13%
Senior Notes [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,045
Weighted Average Interest Rate				5.39%
Senior Notes [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.40%	3.40%
Senior Notes [Member] | Appalachian Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				7.00%	7.00%
Senior Notes [Member] | Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,019
Maturity Date High				2,046
Weighted Average Interest Rate				5.49%
Senior Notes [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.20%	3.20%
Senior Notes [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				7.00%	7.00%
Senior Notes [Member] | Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,035
Weighted Average Interest Rate				5.98%
Senior Notes [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.375%	5.375%
Senior Notes [Member] | Ohio Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.60%	6.60%
Senior Notes [Member] | Public Service Co Of Oklahoma [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,046
Weighted Average Interest Rate				4.80%
Senior Notes [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.05%	3.17%
Senior Notes [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.625%	6.625%
Senior Notes [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,045
Weighted Average Interest Rate				4.86%
Senior Notes [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.75%	3.55%
Senior Notes [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.45%	6.45%
Pollution Control Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[7]			2,016
Maturity Date High	[7]			2,042
Weighted Average Interest Rate				2.97%
Pollution Control Bonds [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				0.68%	0.01%
Pollution Control Bonds [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.30%	6.30%
Pollution Control Bonds [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[7]			2,016
Maturity Date High	[7]			2,042
Weighted Average Interest Rate				1.96%
Pollution Control Bonds [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				0.69%	0.01%
Pollution Control Bonds [Member] | Appalachian Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.38%	5.375%
Pollution Control Bonds [Member] | Appalachian Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 104,000
Due Date			2,017
Pollution Control Bonds [Member] | Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[7]			2,016
Maturity Date High	[7]			2,025
Weighted Average Interest Rate				2.04%
Pollution Control Bonds [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				0.74%	0.01%
Pollution Control Bonds [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.625%	4.625%
Pollution Control Bonds [Member] | Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[7]			2,038
Maturity Date High	[7]			2,038
Weighted Average Interest Rate				5.80%
Pollution Control Bonds [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.80%	5.80%
Pollution Control Bonds [Member] | Ohio Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.80%	5.80%
Pollution Control Bonds [Member] | Public Service Co Of Oklahoma [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,020
Maturity Date High				2,020
Weighted Average Interest Rate				4.45%
Pollution Control Bonds [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.45%	4.45%
Pollution Control Bonds [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.45%	4.45%
Pollution Control Bonds [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low	[7]			2,018
Maturity Date High	[7]			2,019
Weighted Average Interest Rate				3.62%
Pollution Control Bonds [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.60%	1.60%
Pollution Control Bonds [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.95%	4.95%
Securitization Bonds [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,031
Weighted Average Interest Rate				3.66%
Securitization Bonds [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				0.88%	0.88%
Securitization Bonds [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				5.31%	6.25%
Securitization Bonds [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,024
Maturity Date High				2,031
Weighted Average Interest Rate				2.91%
Securitization Bonds [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.008%	2.008%
Securitization Bonds [Member] | Appalachian Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.772%	3.772%
Securitization Bonds [Member] | Appalachian Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		$ 12,000
Securitization Bonds [Member] | Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,020
Weighted Average Interest Rate				1.75%
Securitization Bonds [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				0.958%	0.958%
Securitization Bonds [Member] | Ohio Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.049%	2.049%
Securitization Bonds [Member] | Ohio Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 22,000
Securitization Bonds [Member] | AEP Texas Central Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			90,000
Other Long Term Debt [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,059
Weighted Average Interest Rate				2.08%
Other Long Term Debt [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.15%	1.15%
Other Long Term Debt [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				13.718%	13.718%
Other Long Term Debt [Member] | Appalachian Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,019
Maturity Date High				2,026
Weighted Average Interest Rate				2.27%
Other Long Term Debt [Member] | Appalachian Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.06%	13.718%
Other Long Term Debt [Member] | Appalachian Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				13.718%	13.718%
Other Long Term Debt [Member] | Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,018
Maturity Date High				2,025
Weighted Average Interest Rate				2.43%
Other Long Term Debt [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.15%	1.81%
Other Long Term Debt [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.00%	6.00%
Other Long Term Debt [Member] | Ohio Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,028
Maturity Date High				2,028
Weighted Average Interest Rate				1.15%
Other Long Term Debt [Member] | Ohio Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.15%	1.15%
Other Long Term Debt [Member] | Ohio Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.15%	1.15%
Other Long Term Debt [Member] | Public Service Co Of Oklahoma [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,027
Weighted Average Interest Rate				1.96%
Other Long Term Debt [Member] | Public Service Co Of Oklahoma [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.92%	1.587%
Other Long Term Debt [Member] | Public Service Co Of Oklahoma [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				3.00%	3.00%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,017
Maturity Date High				2,023
Weighted Average Interest Rate				2.48%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				2.346%	1.82%
Other Long Term Debt [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.28%	1.82%
Other Long Term Debt [Member] | AEP Generation Resources [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 500,000
Due Date			2,017
Senior Unsecured Notes [Member] | Southwestern Electric Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt			$ 250,000
Debt Instrument, Interest Rate, Stated Percentage			5.55%
Due Date			2,017
Notes Payable [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,032
Weighted Average Interest Rate				2.45%
Notes Payable [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.456%	0.925%
Notes Payable [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.37%	6.60%
Notes Payable [Member] | Indiana Michigan Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,016
Maturity Date High				2,021
Weighted Average Interest Rate				1.63%
Notes Payable [Member] | Indiana Michigan Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.456%	0.925%
Notes Payable [Member] | Indiana Michigan Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				1.81%	2.12%
Notes Payable [Member] | Indiana Michigan Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		7,000	$ 20,000
Notes Payable [Member] | Southwestern Electric Power Co [Member]
Long- term Debt by Type of Debt and Maturity
Maturity Date Low				2,024
Maturity Date High				2,032
Weighted Average Interest Rate				5.17%
Notes Payable [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				4.58%	4.58%
Notes Payable [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Long- term Debt by Type of Debt and Maturity
Interest Rate				6.37%	6.37%
Notes Payable [Member] | Southwestern Electric Power Co [Member] | Subsequent Event [Member]
Financing Activities (Textuals) [Abstract]
Repayments of Long-term Debt		$ 2,000
Includes Debt Included In Liabilities Held For Sale [Member]
Long-term Debt
Senior Unsecured Notes				$ 14,761,000
Total Long-term Debt Outstanding	[8]			20,391,200
Outstanding Long-term Debt
Principal Amount, 2017				3,013,400
Principal Amount, Total				20,519,600
Unamortized Discount, Net and Debt Issuance Costs				(128,400)
Total Long-term Debt Outstanding	[8]			$ 20,391,200
[1]	For certain series of pollution control bonds, interest rates are subject to periodic adjustment. Certain series may be purchased on demand at periodic interest adjustment dates. Letters of credit from banks and insurance policies support certain series.
[2]	Notes payable represent outstanding promissory notes issued under term loan agreements and credit agreements with a number of banks and other financial institutions. At expiration, all notes then issued and outstanding are due and payable. Interest rates are both fixed and variable. Variable rates generally relate to specified short-term interest rates.
[3]	.
[4]	Spent nuclear fuel obligation consists of a liability along with accrued interest for disposal of spent nuclear fuel (see “SNF Disposal” section of Note 6).
[5]	Amount of securitized debt for receivables as accounted for under the “Transfers and Servicing” accounting guidance.
[6]	Weighted average rate.
[7]	Certain pollution control bonds are subject to redemption earlier than the maturity date. Consequently, these bonds have been classified for maturity purposes as Long-term Debt Due Within One Year - Nonaffiliated on the balance sheets.
[8]	Amount includes debt related to the Lawrenceburg Plant that has been classified as Liabilities Held for Sale on the balance sheet and has a fair value of $172 million. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.

Stock-Based Compensation (Detai

Stock-Based Compensation (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Stock Based Compensation (Textuals) [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant		10,000,000
Number of Shares Remaining Available for Issuance Under the AEP Long-Term Incentive Plan		9,822,644
Reduction in Aggregate Common Shares Authorized Per Share Issued Pursuant to Stock Options or Stock Appreciation Rights		0.286
Performance Units [Member]
Performance Units
Awarded Units		597,400	575,000	16,900
Weighted Average Grant Date Fair Value, Granted		$ 62.77	$ 59.19	$ 49.73
Vesting Period (in years)		3 years	3 years	3 years
Certified Performance Scores and Units Earned
Certified Performance Score		163.90%	176.30%	147.80%
Performance Units Earned		1,111,966	1,202,107	889,697
Performance Units Manditorily Deferred as AEP Career Shares		9,963	41,707	40,831
Performance Units Voluntarily Deferred into the Incentive Compensation Deferral Program		51,684	54,074	39,526
Performance Units to be Paid in Cash		1,050,319	1,106,326	809,340
Cash Payouts
Cash Payouts for Performance Units		$ 62.7	$ 48.1	$ 29.3
Cash Payouts for AEP Career Share Distributions		$ 9.1	$ 3	$ 4.3
Restricted Stock Units Including Units Awarded for Dividends
Weighted Average Grant Date Fair Value		$ 62.77	$ 59.19	$ 49.73
Status of Nonvested Restricted Shares and Restricted Stock Units
Weighted Average Grant Date Fair Value, Granted		62.77	59.19	49.73
Stock Unit Accumulation Plan for Non-employee Directors
Weighted Average Grant Date Fair Value		$ 62.77	$ 59.19	$ 49.73
Stock Based Compensation (Textuals) [Abstract]
Performance Score by HR Committee, Lower Range		0.00%
Performance Score by HR Committee, Higher Range		200.00%
Restricted Stock Units (RSUs) [Member]
Stock Based Compensation (Textuals) [Abstract]
Maximum Contractual Term of Outstanding Restricted Stock Units (in months)		40 months
Performance Units and AEP Career Shares Reinvested Dividends Portion For [Member]
Performance Units
Awarded Units		89,200	103,600	98,900
Weighted Average Grant Date Fair Value, Granted		$ 63.83	$ 54.35	$ 53.35
Vesting Period	[1]	(a)	(a)	(a)
Restricted Stock Units Including Units Awarded for Dividends
Weighted Average Grant Date Fair Value		$ 63.83	$ 54.35	$ 53.35
Status of Nonvested Restricted Shares and Restricted Stock Units
Weighted Average Grant Date Fair Value, Granted		63.83	54.35	53.35
Stock Unit Accumulation Plan for Non-employee Directors
Weighted Average Grant Date Fair Value		$ 63.83	$ 54.35	$ 53.35
Restricted Shares and Restricted Stock Units [Member]
Total Fair Value and Total Intrinsic Value of Restricted Shares and Restricted Stock Units Vested
Fair Value of Restricted Shares and Restricted Stock Units Vested		$ 16.4	$ 18.3	$ 18.7
Intrinsic Value of Restricted Shares and Restricted Stock Units Vested	[2]	$ 21	$ 24.2	$ 24.9
Restricted Stock [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 62.88	$ 58.56	$ 50.36
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		242,000	397,500	64,100
Weighted Average Grant Date Fair Value		$ 62.88	$ 58.56	$ 50.36
Status of Nonvested Restricted Shares and Restricted Stock Units
Nonvested, Shares/Units, Beginning Balance		721,300
Nonvested, Weighted Average Grant Date Fair Value, Beginning of Period		$ 52.48
Shares/Units, Granted		242,000	397,500	64,100
Weighted Average Grant Date Fair Value, Granted		$ 62.88	$ 58.56	$ 50.36
Shares/Units, Vested		(326,700)
Weighted Average Grant Date Fair Value, Vested		$ 50.07
Shares/Units, Forfeited		(33,000)
Weighted Average Grant Date Fair Value, Shares/Units, Forfeited		$ 55.81
Nonvested, Shares/Units, Ending Balance		603,600	721,300
Nonvested, Weighted Average Grant Date Fair Value, End of Period		$ 57.54	$ 52.48
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		242,000	397,500	64,100
Weighted Average Grant Date Fair Value		$ 62.88	$ 58.56	$ 50.36
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		242,000	397,500	64,100
Total Aggregate Intrinsic Value of Nonvested Shares		$ 38
Weighted Average Remaining Contractual Life of Nonvested Shares (in years)		1.7 years
Stock Unit Accumulation Plan for Non Employee Directors [Member]
Performance Units
Weighted Average Grant Date Fair Value, Granted		$ 64.96	$ 55.46	$ 54.08
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		19,100	24,900	25,400
Weighted Average Grant Date Fair Value		$ 64.96	$ 55.46	$ 54.08
Status of Nonvested Restricted Shares and Restricted Stock Units
Shares/Units, Granted		19,100	24,900	25,400
Weighted Average Grant Date Fair Value, Granted		$ 64.96	$ 55.46	$ 54.08
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		19,100	24,900	25,400
Weighted Average Grant Date Fair Value		$ 64.96	$ 55.46	$ 54.08
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		19,100	24,900	25,400
Number of Years After Termination of Board Service Participant Can Elect to Have Stock Units Paid in Cash		10 years
Cash Payouts for Stock Unit Accumulation Plan		$ 0	$ 1	$ 5
Stock Based Compensation [Member]
Compensation Cost and Actual Tax Benefit Realized for the Tax Deductions from Compensation Cost for Share-based Payment Arrangements
Compensation Cost for Share-based Payment Arrangements	[3]	66.5	63.8	85.4
Actual Tax Benefit Realized		23.3	22.3	29.9
Total Compensation Cost Capitalized		20.8	$ 20.3	$ 23.1
Stock Based Compensation (Textuals) [Abstract]
Total Unrecognized Compensation Cost Related to Unvested Share-based Compensation Arrangements Granted		$ 62
Weighted-average Period of Unrecognized Compensation Costs (in years)		1.37 years
Granted 2010 [Member] | Restricted Stock [Member] | Granted to Previous Chief Executive Officer Succession Candidates [Member] | August 3, 2013 through August 3, 2015 [Member]
Restricted Stock Units Including Units Awarded for Dividends
Awarded Units		165,520
Status of Nonvested Restricted Shares and Restricted Stock Units
Shares/Units, Granted		165,520
Stock Unit Accumulation Plan for Non-employee Directors
Awarded Units		165,520
Stock Based Compensation (Textuals) [Abstract]
Shares/Units, Granted		165,520
[1]	The vesting period for the reinvested dividends on performance units is equal to the remaining life of the related performance units. Dividends on AEP career shares vest immediately when the dividend is awarded but are not paid in cash until after the participant’s AEP employment ends.
[2]	Intrinsic value is calculated as market price at exercise date.
[3]	Compensation cost for share-based payment arrangements is included in Other Operation and Maintenance expenses on the statements of income.

Related Party Transactions (Det

Related Party Transactions (Details) $ in Millions		12 Months Ended
		Dec. 31, 2016USD ($)plantMW	Dec. 31, 2015USD ($)		Dec. 31, 2014USD ($)
Related Party Transactions (Textuals)
Aggregate Power Participation Ratio		43.47%
Ohio Valley Electric Corporation [Member]
Ownership and Investment In OVEC
Ownership		43.47%
Investment		$ 4.4
Indiana Michigan Power Co to Appalachian Power Co [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		$ 0	$ 0
Indiana Michigan Power Co to Kentucky Power Co [Member]
Related Party Transactions (Textuals)
Percentage of Power Sold under Unit Power Agreement		30.00%
Indiana Michigan Power Co to Public Service Co of Oklahoma [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		$ 0.3	0.6
Indiana Michigan Power Co to Southwestern Electric Power Co [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		0.9	1.8
Public Service Co of Oklahoma to Appalachian Power Co [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		0.3	0.3
Public Service Co of Oklahoma to Indiana Michigan Power Co [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		0.3	0.4
Public Service Co of Oklahoma to Southwestern Electric Power Co [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		0.3	0.6
Southwestern Electric Power Co to Appalachian Power Co [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		0.3	0.3
Southwestern Electric Power Co to Indiana Michigan Power Co [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		0.8	1.2
Southwestern Electric Power Co to Public Service Co of Oklahoma [Member]
Affiliate Railcar Agreement
Revenue Related to Affiliate Railcar Agreement		0.2	0.6
AEP Generating Co to Indiana Michigan Power Co [Member]
Cook Coal Terminal
Coal Transloading Services		12.8	15.8		$ 16.2
Railcar Maintenance		$ 1.7	2		2.5
AEP Generating Co to Kentucky Power Co [Member]
Related Party Transactions (Textuals)
Percentage of Power Sold under Unit Power Agreement		30.00%
AEP Generating Co to Public Service Co of Oklahoma [Member]
Cook Coal Terminal
Railcar Maintenance		$ 0.6	0.2		0.3
AEP Generating Co To Southwestern Electric Power Co [Member]
Cook Coal Terminal
Railcar Maintenance		$ 3.3	2.8		3.3
American Electric Power [Member] | Ohio Valley Electric Corporation [Member]
Ownership and Investment In OVEC
Ownership		39.17%
Investment		$ 4
AEP Generating Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		14.8	16.1		22.7
Central Machine Shop
Billings for Services from Central Machine Shop Facility		0	0.1		0.1
AEP Generation Resources [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		0.3	4.9		5.2
Central Machine Shop
Billings for Services from Central Machine Shop Facility		2	2.7		2.8
AEP River Operations LLC [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		$ 0	15.5		25.3
AEP Subsidiaries [Member]
Related Party Transactions (Textuals)
Aggregate Power Participation Ratio		43.47%
Appalachian Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		$ 142.1	147.8		144.5
Cost of Purchased Power from Affiliate		0	0		4.7
Transmission Agreement
Net Charges from Transmission Agreement		103.2	92.7		84.7
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		36.9	37.7		36.1
Power Purchased by the Registrant Subsidiaries from OVEC
Amount of Power Purchased from OVEC		88	87.2		96.9
Sales and Purchases of Property
Related Party Sales of Property		4.5	9.4		3
Related Party Purchases of Property		$ 1.5	8.6		0.9
Related Party Transactions (Textuals)
Aggregate Power Participation Ratio		43.47%
Appalachian Power Co [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]				4.7
Appalachian Power Co [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Appalachian Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		$ 0			0
Appalachian Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Appalachian Power Co [Member] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0
Appalachian Power Co [Member] | Auction Purchases From AEP Energy Partners [Member] [Domain]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0
Appalachian Power Co [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Appalachian Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0
Appalachian Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0		0
Appalachian Power Co [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]				0.2
Appalachian Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		126	132.1		141.7
Appalachian Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0			0.6
Appalachian Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	9.2	10.6
Appalachian Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Appalachian Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1.3	0.7		(1.6)
Appalachian Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		5.6	4.4		3.6
Indiana Michigan Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		26.2	27.4		4.2
Cost of Purchased Power from Affiliate		228.6	232.1		270
Transmission Agreement
Net Charges from Transmission Agreement		53	38		39.7
Central Machine Shop
Billings for Services from Central Machine Shop Facility		2.9	2.5		1.7
Power Purchased by the Registrant Subsidiaries from OVEC
Amount of Power Purchased from OVEC		44	43.7		48.5
Sales and Purchases of Property
Related Party Sales of Property		5.2	3		1.3
Related Party Purchases of Property		$ 2.7	8.1		1.4
Related Party Transactions (Textuals)
Barge Towing and Chartering Services			19		24
Aggregate Power Participation Ratio		43.47%
Indiana Michigan Power Co [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]				1.6
Indiana Michigan Power Co [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Indiana Michigan Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		$ 0			0
Indiana Michigan Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Indiana Michigan Power Co [Member] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0
Indiana Michigan Power Co [Member] | Auction Purchases From AEP Energy Partners [Member] [Domain]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0
Indiana Michigan Power Co [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Indiana Michigan Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0
Indiana Michigan Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		228.6	232.1		268.4
Indiana Michigan Power Co [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]				0.5
Indiana Michigan Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Indiana Michigan Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0			0.4
Indiana Michigan Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	12	17.1
Indiana Michigan Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Indiana Michigan Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		12.2	8.4		1.7
Indiana Michigan Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		2	1.9		1.6
Kentucky Power Co [Member]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		5.3	4.6		5
Central Machine Shop
Billings for Services from Central Machine Shop Facility		1.5	1.3		1.2
Ohio Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		17.3	84.1		165.2
Cost of Purchased Power from Affiliate		141.9	527.1		1,349.7
Generation Deferrals		(82.7)	(30.7)	[3]	(157)	[3]
Transmission Agreement
Net Charges from Transmission Agreement		143.6	81		17
Power Purchased by the Registrant Subsidiaries from OVEC
Amount of Power Purchased from OVEC		111.7	110.8		123.1
Sales and Purchases of Property
Related Party Sales of Property		1.9	2.4		0.5
Related Party Purchases of Property		$ 1.7	2.1		1.9
Related Party Transactions (Textuals)
Aggregate Power Participation Ratio		43.47%
Ohio Power Co [Member] | Ohio Valley Electric Corporation [Member]
Ownership and Investment In OVEC
Ownership		4.30%
Investment		$ 0.4
Ohio Power Co [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]				0.1
Ohio Power Co [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Ohio Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0			0
Ohio Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			269.2		1,305.2
Ohio Power Co [Member] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	110.1	225.2
Ohio Power Co [Member] | Auction Purchases From AEP Energy Partners [Member] [Domain]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	7.7
Ohio Power Co [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					44.4
Ohio Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	24.1	32.7
Ohio Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0		0
Ohio Power Co [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]				1.1
Ohio Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Ohio Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0			0
Ohio Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	0	0
Ohio Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	29.7		44.1
Ohio Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		(2)	35.5		104.1
Ohio Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		$ 19.3	18.9		15.9
Ohio Valley Electric Corporation [Member]
Related Party Transactions (Textuals)
Approximate OVEC Generating Capacity (In MWs) | MW		2,400
Number of OVEC Generating Plants | plant		2
Outstanding Indebtedness		$ 1,500
Public Service Co Of Oklahoma [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		2.6	4.6		7.1
Cost of Purchased Power from Affiliate		3.7	0		11
Transmission Coordination Agreement
Net (Revenues) Expenses from Transmission Coordination Agreement		19.6	15		14.1
Central Machine Shop
Billings for Services from Central Machine Shop Facility		0.5	0.2		0.3
Sales and Purchases of Property
Related Party Sales of Property		7.5	7.1		0.5
Related Party Purchases of Property		3.2	0.6		2.1
Public Service Co Of Oklahoma [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]				0
Public Service Co Of Oklahoma [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					1
Public Service Co Of Oklahoma [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		3.7			10
Public Service Co Of Oklahoma [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Public Service Co Of Oklahoma [Member] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0
Public Service Co Of Oklahoma [Member] | Auction Purchases From AEP Energy Partners [Member] [Domain]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0
Public Service Co Of Oklahoma [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Public Service Co Of Oklahoma [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0
Public Service Co Of Oklahoma [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0		0
Public Service Co Of Oklahoma [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]				0
Public Service Co Of Oklahoma [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		3.8
Public Service Co Of Oklahoma [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0			0
Public Service Co Of Oklahoma [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	0	0
Public Service Co Of Oklahoma [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		0
Public Service Co Of Oklahoma [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		(1.7)	0.2		0
Public Service Co Of Oklahoma [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		4.3	4.4		3.3
Southwestern Electric Power Co [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		24.5	16.6		26.3
Cost of Purchased Power from Affiliate		0	0		3.8
Transmission Coordination Agreement
Net (Revenues) Expenses from Transmission Coordination Agreement		(19.6)	(15)		(14.1)
Central Machine Shop
Billings for Services from Central Machine Shop Facility		0.9	0.8		0.1
Sales and Purchases of Property
Related Party Sales of Property		1	0.8		1.2
Related Party Purchases of Property		6.5	7.4		4
Southwestern Electric Power Co [Member] | Purchases under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[1]				0
Southwestern Electric Power Co [Member] | Direct Purchases from East Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Southwestern Electric Power Co [Member] | Direct Purchases from West Affiliates [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0			3.8
Southwestern Electric Power Co [Member] | Direct Purchases from AGR [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate			0		0
Southwestern Electric Power Co [Member] | Auction Purchases From AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0
Southwestern Electric Power Co [Member] | Auction Purchases From AEP Energy Partners [Member] [Domain]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0
Southwestern Electric Power Co [Member] | Direct Purchases from AEPEP [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate					0
Southwestern Electric Power Co [Member] | Auction Purchases from AEPSC [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate	[2]	0	0
Southwestern Electric Power Co [Member] | Direct Purchases from AEGCo [Member]
Affiliated Revenues and Purchases
Cost of Purchased Power from Affiliate		0	0		0
Southwestern Electric Power Co [Member] | Sales under Interconnection Agreement [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[1]				0
Southwestern Electric Power Co [Member] | Direct Sales to East Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		0	0		10.1
Southwestern Electric Power Co [Member] | Direct Sales to West Affiliates [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		3.7			0.3
Southwestern Electric Power Co [Member] | Auction Sales to OPCo [Member]
Affiliated Revenues and Purchases
Affiliated Revenues	[2]	0	0
Southwestern Electric Power Co [Member] | Direct Sales to AEPEP [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		(0.2)	(0.2)		0
Southwestern Electric Power Co [Member] | Transmission Agreement and Transmission Coordination Agreement Sales [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		19.4	15.2		14.1
Southwestern Electric Power Co [Member] | Other Revenues [Member]
Affiliated Revenues and Purchases
Affiliated Revenues		1.6	1.6		1.8
Wheeling Power Co [Member] [Domain]
Barging, Urea Transloading and Other Services
Expenses from Barging, Urea Transloading and Other Services		$ 4.8	$ 0		$ 0
[1]	Includes December 2013 true-up activity subsequent to agreement termination.
[2]	Refer to the Ohio Auctions section below for further information regarding these amounts.
[3]	Amounts exclude $31 million and $157 million in 2015 and 2014, respectively, which are now presented as Generation Deferrals on the Statement of Income.

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	$ 1,705		$ 2,024
Securitized Transition Assets	$ 1,486.1		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	$ 28		29		$ 32
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Assets [Member]
ASSETS
Assets	170.6		165.3
Protected Cell Of Energy Insurance Services, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
Protected Cell Of Energy Insurance Services, Inc. [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	1.1		1.9
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Assets [Member]
ASSETS
Assets	171.7		167.2
Protected Cell Of Energy Insurance Services, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	31.8		41.8
Protected Cell Of Energy Insurance Services, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	97.3		83.9
Protected Cell Of Energy Insurance Services, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	42.6		41.5
Protected Cell Of Energy Insurance Services, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	171.7		167.2
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Proceeds from Partnership Contribution	45		47
Transource Energy [Member] | Current Assets [Member]
ASSETS
Assets	16.3		10.8
Transource Energy [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	313		227.2
Transource Energy [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	5.4		5.5
Transource Energy [Member] | Total Assets [Member]
ASSETS
Assets	334.7		243.5
Transource Energy [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	31.7		36.6
Transource Energy [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	134.4		113
Transource Energy [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	168.6		93.9
Transource Energy [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	334.7		243.5
AEP Renewables [Member] | Current Assets [Member]
ASSETS
Assets	0
AEP Renewables [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	130.4
AEP Renewables [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	9
AEP Renewables [Member] | Total Assets [Member]
ASSETS
Assets	139.4
AEP Renewables [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	126.7
AEP Renewables [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	11.3
AEP Renewables [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1.4
AEP Renewables [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	$ 139.4
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	$ 945.7		925.7
AEP Credit, Inc. [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
AEP Credit, Inc. [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	10.3		6.4
AEP Credit, Inc. [Member] | Total Assets [Member]
ASSETS
Assets	956		932.1
AEP Credit, Inc. [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	877.4		855.1
AEP Credit, Inc. [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0.6		0.3
AEP Credit, Inc. [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	78		76.7
AEP Credit, Inc. [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	$ 956		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%
Percentage of Equity Capital Structure in PATH's Stipulation Agreement	50.00%
Percentage of Cost of Long Term Debt for PATH's Stipulation Agreement	4.70%
Percentage of PATH WV's Lowered Authorized ROE	8.11%
Percentage of PATH WV's Previously Authorized ROE	10.40%
PATH West Virginia Transmission Co, LLC [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	$ 18.8		18.8
Maximum Exposure	18.8		18.8
PATH West Virginia Transmission Co, LLC [Member] | Retained Earnings [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	(2.3)		2.2
Maximum Exposure	(2.3)		2.2
PATH West Virginia Transmission Co, LLC [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	16.5		21
Maximum Exposure	16.5		21
AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	1,200		1,500
Securitized Transition Assets	1,100		1,300
AEP Texas Central Transition Funding Co [Member] | Current Assets [Member]
ASSETS
Assets	184.8		234.1
AEP Texas Central Transition Funding Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
AEP Texas Central Transition Funding Co [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	1,149.4	[1]	1,365.7	[2]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	61.1		68.2
AEP Texas Central Transition Funding Co [Member] | Total Assets [Member]
ASSETS
Assets	1,334.2		1,599.8
AEP Texas Central Transition Funding Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	251.9		291.7
AEP Texas Central Transition Funding Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1,064.2		1,290
AEP Texas Central Transition Funding Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	18.1		18.1
AEP Texas Central Transition Funding Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	$ 1,334.2		1,599.8
Great Plains Energy Inc. [Member] | Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage	13.50%
Cleco Power, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage of VIE Sales of Lignite Produced	50.00%
Appalachian Power Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	$ 318.9		341.5
Securitized Transition Assets	305.3		328
Appalachian Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	244.2		227.5		216.5
Appalachian Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	36.7		25.8
Maximum Exposure	36.7		25.8
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	319		342
Securitized Transition Assets	305		328
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Assets [Member]
ASSETS
Assets	20.2		18.5
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	309	[3]	332	[4]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	3.7		4
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Total Assets [Member]
ASSETS
Assets	329.2		350.5
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	27.3		27.1
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	300.6		321.5
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	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	329.2		350.5
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Variable Interest Entities (Textuals) [Abstract]
Payments Made by I&M to DCC Fuel	101		115		109
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Assets [Member]
ASSETS
Assets	135.5		91.1
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	233.9		159.9
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	116.2		84.6
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Assets [Member]
ASSETS
Assets	485.6		335.6
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	131.3		84.8
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	354.3		250.8
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0		0
Indiana Michigan Power Co [Member] | DCC Fuel [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	485.6		335.6
Indiana Michigan Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	147.7		139.5		133.2
Indiana Michigan Power Co [Member] | Billings from AEP Generating Company [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	229		232		268
Indiana Michigan Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	24.2		16.6
Maximum Exposure	24.2		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 Balance Sheet	22		17
Ohio Power Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	140.2		185.3
Securitized Transition Assets	62.1		85.9
Ohio Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	181.1		177.8		169
Ohio Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	28.1		23.3
Maximum Exposure	28.1		23.3
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds	140		185
Securitized Transition Assets	62		86
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Assets [Member]
ASSETS
Assets	30.3		31.2
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	0		0
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	117.1	[5]	162	[6]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation	55		76.1
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Total Assets [Member]
ASSETS
Assets	147.4		193.2
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	47.5		47.3
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	98.6		144.6
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	1.3		1.3
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	147.4		193.2
Public Service Co Of Oklahoma [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	111		107.3		101.4
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	16		12.6
Maximum Exposure	16		12.6
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	162		152		151
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Assets [Member]
ASSETS
Assets	60.2		61.7
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Net Property Plant And Equipment [Member]
ASSETS
Assets	112		147
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Other Noncurrent Assets [Member]
ASSETS
Assets	89.8		61.8
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Assets [Member]
ASSETS
Assets	262		270.5
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Current Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	26.3		47.7
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Noncurrent Liabilities [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	235.3		222.3
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	0.4		0.5
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member] | Total Liabilities And Equity [Member]
LIABILITIES AND EQUITY
Liabilities and Equity	262		270.5
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	$ 65		93		56
Percentage of VIE Sales of Lignite Produced	50.00%
Percentage of DHLCs Debt Guaranteed by Each SWEPCo and CLECO	50.00%
Percentage of Management Fee Received by SWEPCo from DHLC	100.00%
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Capital Contribution From Parent [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	$ 7.6		7.6
Maximum Exposure	7.6		7.6
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Retained Earnings [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	15.7		7.7
Maximum Exposure	15.7		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 Balance Sheet	0		0
Maximum Exposure	91.3		82.9
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member] | Total Investment [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	23.3		15.3
Maximum Exposure	114.6		98.2
Southwestern Electric Power Co [Member] | Billings from AEP Service Corporation [Member]
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE	147		141.4		$ 140.3
Southwestern Electric Power Co [Member] | Carrying Amount in AEP Service Corporation's Accounts Payable [Member]
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Balance Sheet	21.8		16.4
Maximum Exposure	$ 21.8		$ 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%
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 2) [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage Interest in Rockport Plant Unit 2 Lease	50.00%
AEP Generating Co [Member] | Lawrenceburg Generating Station [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share	100.00%
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage	86.50%
[1]	Includes an intercompany item eliminated in consolidation of $61.1 million.
[2]	Includes an intercompany item eliminated in consolidation of $68.2 million.
[3]	Includes an intercompany item eliminated in consolidation of $3.7 million.
[4]	Includes an intercompany item eliminated in consolidation of $4 million.
[5]	Includes an intercompany item eliminated in consolidation of $55 million.
[6]	Includes an intercompany item eliminated in consolidation of $76.1 million.

Property, Plant and Equipment77

Property, Plant and Equipment (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 19,848.9		$ 25,559.8
Property, Plant and Equipment, Transmission		16,658.7		14,247.9
Property, Plant and Equipment, Distribution		18,900.8		18,046.9
Property, Plant and Equipment, Other		3,444.3		3,722.9
Property, Plant and Equipment, Construction Work in Progress		3,183.9		3,903.9
Accumulated Depreciation		16,397.3		19,348.2
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		45,639.3	[1]	46,133.2
Asset Retirement Obligations (ARO)
Beginning Balance	[2],[3],[4],[5]	1,916.3		2,019.6
Accretion Expense		91.3		101.4
Liabilities Incurred		0.8		58
Liabilities Settled		(139.9)	[6]	(147.2)	[7]
Revisions in Cash Flow Estimates		66.4		(115.5)	[8]
Ending Balance	[2],[3],[4],[5]	1,934.9		1,916.3		$ 2,019.6
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		113.2		131.9		102.9
Allowance for Borrowed Funds Used During Construction		51.7		61.3		44.5
Jointly-owned Electric Facilities
Utility Plant in Service		3,458.2		4,917.3
Construction Work in Progress		18.8		239.6
Accumulated Depreciation		1,110.1		1,773
Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		6,332.8		6,200.8
Property, Plant and Equipment, Transmission		2,796.9		2,408.1
Property, Plant and Equipment, Distribution		3,569.1		3,402.5
Property, Plant and Equipment, Other		373.5		345.5
Property, Plant and Equipment, Construction Work in Progress		390.3		475.1
Accumulated Depreciation		3,636.8		3,407.6
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,825.8		9,424.4
Asset Retirement Obligations (ARO)
Beginning Balance	[3],[4]	140.2		148.4
Accretion Expense		7.6		8.3
Liabilities Incurred		0		0
Liabilities Settled		(35.3)		(34)
Revisions in Cash Flow Estimates		14.6		17.5
Ending Balance	[3],[4]	127.1		140.2		148.4
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		11.7		13.8		7.1
Allowance for Borrowed Funds Used During Construction		$ 6.3		$ 6.9		$ 3.8
Appalachian Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		121 years		121 years		121 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		68 years		68 years		87 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		57 years		57 years		57 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		55 years		55 years		55 years
Appalachian Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		35 years		35 years		40 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		15 years		15 years		15 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		10 years		10 years		13 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		5 years		24 years
Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 4,056.1		$ 3,841.7
Property, Plant and Equipment, Transmission		1,472.8		1,406.9
Property, Plant and Equipment, Distribution		1,899.3		1,790.8
Property, Plant and Equipment, Other		550.2		662.3
Property, Plant and Equipment, Construction Work in Progress		654.2		519.8
Accumulated Depreciation		3,005.1		3,018
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,627.5		5,203.5
Asset Retirement Obligations (ARO)
Beginning Balance	[3],[4],[5]	1,253.8		1,342.5
Accretion Expense		55.6		64.3
Liabilities Incurred		0		0
Liabilities Settled		(62.6)	[6]	(5.7)
Revisions in Cash Flow Estimates		11.3		(147.3)
Ending Balance	[3],[4],[5]	1,258.1		1,253.8		$ 1,342.5
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		15.3		11.6		18.9
Allowance for Borrowed Funds Used During Construction		7.2		5		$ 8
Property, Plant and Equipment (Textuals) [Abstract]
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant		1,240		1,180
Fair Value of Legally Restricted Assets		$ 1,950		$ 1,800
Indiana Michigan Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		132 years		132 years		132 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		75 years		75 years		75 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		70 years		70 years		70 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		45 years		45 years		45 years
Indiana Michigan Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		59 years		59 years		59 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		50 years		50 years		50 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		10 years		10 years		15 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		5 years		14 years
Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Transmission		$ 2,319.2		$ 2,235.6
Property, Plant and Equipment, Distribution		4,457.2		4,287.7
Property, Plant and Equipment, Other		443.7		408.2
Property, Plant and Equipment, Construction Work in Progress		221.5		171.9
Accumulated Depreciation		2,116		2,048.7
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,325.6		5,054.7
Asset Retirement Obligations (ARO)
Beginning Balance	[3]	1.4		1.4
Accretion Expense		0.1		0
Liabilities Incurred		0.2		0
Liabilities Settled		0		0
Revisions in Cash Flow Estimates		0		0
Ending Balance	[3]	1.7		1.4		$ 1.4
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		6		8.8		6.9
Allowance for Borrowed Funds Used During Construction		$ 3.3		$ 4.8		$ 4.4
Ohio Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		60 years		60 years		60 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		57 years		57 years		57 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		50 years		50 years		50 years
Ohio Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		39 years		39 years		39 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		7 years		7 years		7 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		5 years		7 years
Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 1,559.3		$ 1,302.6
Property, Plant and Equipment, Transmission		832.8		815.4
Property, Plant and Equipment, Distribution		2,322.4		2,206.7
Property, Plant and Equipment, Other		233.2		405.7
Property, Plant and Equipment, Construction Work in Progress		148.2		315.3
Accumulated Depreciation		1,272.7		1,352.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,823.2		3,693.2
Asset Retirement Obligations (ARO)
Beginning Balance	[3],[4]	47.8		38.1
Accretion Expense		3		2.6
Liabilities Incurred		0.1		5.6
Liabilities Settled		(1)		(0.4)
Revisions in Cash Flow Estimates		3.5		1.9
Ending Balance	[3],[4]	53.4		47.8		$ 38.1
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		6.2		8.8		3.1
Allowance for Borrowed Funds Used During Construction		$ 3.4		$ 5		$ 1.8
Public Service Co Of Oklahoma [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		85 years		70 years		70 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		100 years		75 years		75 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		156 years		65 years		65 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		84 years		40 years		40 years
Public Service Co Of Oklahoma [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		35 years		35 years		35 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		45 years		40 years		40 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		27 years		7 years		30 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		5 years		5 years
Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 4,607.6		$ 3,943.5
Property, Plant and Equipment, Transmission		1,584.2		1,387.8
Property, Plant and Equipment, Distribution		2,020.6		1,957.3
Property, Plant and Equipment, Other		670.4		883.5
Property, Plant and Equipment, Construction Work in Progress		113.8		751.3
Accumulated Depreciation		2,567.1		2,602.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,429.5		6,321.1
Asset Retirement Obligations (ARO)
Beginning Balance	[2],[3],[4]	125.4		94.4
Accretion Expense		7		5.9
Liabilities Incurred		0.2		17.1
Liabilities Settled		(8.3)		(5)
Revisions in Cash Flow Estimates		32.2		13
Ending Balance	[2],[3],[4]	156.5		125.4		$ 94.4
Allowance for Funds Used During Construction (AFUDC) and Interest Capitalization
Allowance for Equity Funds Used During Construction		11		26.4		11.9
Allowance for Borrowed Funds Used During Construction		6.9		14.8		$ 6.9
Jointly-owned Electric Facilities
Utility Plant in Service		2,940.9		2,684.9
Construction Work in Progress		14.6		210.3
Accumulated Depreciation		$ 819		$ 769.1
Southwestern Electric Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		70 years		70 years		70 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		70 years		70 years		70 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		65 years		65 years		65 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		51 years		51 years		51 years
Southwestern Electric Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		40 years		40 years		40 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		50 years		50 years		50 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		25 years		25 years		25 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		5 years		7 years
AEP Texas North Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership		54.70%
Conesville Generating Station (Unit No. 4) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[9],[10]	43.50%		43.50%
Utility Plant in Service	[9],[10]	$ 0.1		$ 337.4
Construction Work in Progress	[9],[10]	1.3		2.4
Accumulated Depreciation	[9],[10]	$ 0		$ 76.1
J.M. Stuart Generating Station [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[11]	26.00%		26.00%
Utility Plant in Service	[11]	$ 0		$ 565.5
Construction Work in Progress	[11]	0.8		12.9
Accumulated Depreciation	[11]	$ 0		$ 221.8
Wm. H. Zimmer Generating Station [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[9],[12]	25.40%		25.40%
Utility Plant in Service	[9],[12]	$ 0		$ 815.5
Construction Work in Progress	[9],[12]	0.3		6.4
Accumulated Depreciation	[9],[12]	$ 0		$ 421.7
Dolet Hills Generating Station (Unit No. 1) [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[13]	40.20%		40.20%
Utility Plant in Service	[13]	$ 334.8		$ 332.4
Construction Work in Progress	[13]	5		3.9
Accumulated Depreciation	[13]	$ 207.5		$ 205.9
Dolet Hills Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[13]	40.20%		40.20%
Utility Plant in Service	[13]	$ 334.8		$ 332.4
Construction Work in Progress	[13]	5		3.9
Accumulated Depreciation	[13]	$ 207.5		$ 205.9
Flint Creek Generating Station (Unit No. 1) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[14]	50.00%		50.00%
Utility Plant in Service	[14]	$ 362.4		$ 131.4
Construction Work in Progress	[14]	3.7		195
Accumulated Depreciation	[14]	$ 73.5		$ 70
Flint Creek Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[14]	50.00%		50.00%
Utility Plant in Service	[14]	$ 362.4		$ 131.4
Construction Work in Progress	[14]	3.7		195
Accumulated Depreciation	[14]	$ 73.5		$ 70
Pirkey Generating Station (Unit No. 1) [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[14]	85.90%		85.90%
Utility Plant in Service	[14]	$ 586.4		$ 572.1
Construction Work in Progress	[14]	5.7		5.9
Accumulated Depreciation	[14]	$ 399.5		$ 389.1
Pirkey Generating Station (Unit No. 1) [Member] | Southwestern Electric Power Co [Member] | Public Utilities, Inventory, Lignite [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[14]	85.90%		85.90%
Utility Plant in Service	[14]	$ 586.4		$ 572.1
Construction Work in Progress	[14]	5.7		5.9
Accumulated Depreciation	[14]	$ 399.5		$ 389.1
Oklaunion Generating Station (Unit No. 1) [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[15]	70.30%		70.30%
Utility Plant in Service	[15]	$ 454.8		$ 445.5
Construction Work in Progress	[15]	1.3		7.2
Accumulated Depreciation	[15]	$ 246		$ 236.2
Oklaunion Generating Station (Unit No. 1) [Member] | Public Service Co Of Oklahoma [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[15]	15.60%		15.60%
Utility Plant in Service	[15]	$ 105.2		$ 103
Construction Work in Progress	[15]	0.5		1.8
Accumulated Depreciation	[15]	$ 59.4		$ 58.2
Turk Generating Plant [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[14]	73.30%		73.33%
Utility Plant in Service	[14]	$ 1,657.3		$ 1,649
Construction Work in Progress	[14]	0.2		5.5
Accumulated Depreciation	[14]	$ 138.5		$ 104.1
Turk Generating Plant [Member] | Southwestern Electric Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[14]	73.30%		73.33%
Utility Plant in Service	[14]	$ 1,657.3		$ 1,649
Construction Work in Progress	[14]	0.2		5.5
Accumulated Depreciation	[14]	$ 138.5		$ 104.1
Jointly Owned Electricity Transmission and Distribution System [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[16]
Utility Plant in Service		$ 62.4		$ 68.5
Construction Work in Progress		0.5		0.4
Accumulated Depreciation		$ 45.1		$ 48.1
Rockport Generating Plant (Unit No. 1) [Member] | Indiana Michigan Power Co [Member] | Coal [Member]
Jointly-owned Electric Facilities
Percent of Ownership	[17],[18],[19]	50.00%		50.00%
Utility Plant in Service	[17],[18],[19]	$ 936.1		$ 926.7
Construction Work in Progress	[17],[18],[19]	125.8		58.5
Accumulated Depreciation	[17],[18],[19]	$ 535.1		512.4
Rockport Generating Plant (Unit No. 1) [Member] | AEP Generating Co [Member]
Jointly-owned Electric Facilities
Percent of Ownership		50.00%
Regulated Operation [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	[20]	$ 19,703.9		19,082.8
Property, Plant and Equipment, Transmission		16,658.6		14,219
Property, Plant and Equipment, Distribution		18,898.2		18,046.9
Property, Plant and Equipment, Other		2,902		3,066.7
Property, Plant and Equipment, Construction Work in Progress	[20]	3,072.2		3,774.4
Accumulated Depreciation		16,101.5		16,076.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 45,133.4		$ 42,112.9
Regulated Operation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		132 years		132 years		132 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		100 years		81 years		87 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		156 years		75 years		75 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		84 years		75 years		75 years
Regulated Operation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		35 years		35 years		31 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		15 years		15 years		15 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		7 years		7 years		7 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		5 years		5 years		5 years
Regulated Operation [Member] | Generation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		4.00%		3.10%		3.50%
Regulated Operation [Member] | Generation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.10%		0.40%		1.70%
Regulated Operation [Member] | Transmission [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		2.70%		2.70%
Regulated Operation [Member] | Transmission [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.50%		1.40%		1.40%
Regulated Operation [Member] | Distribution [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.70%		3.70%		3.70%
Regulated Operation [Member] | Distribution [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.60%		2.50%		2.40%
Regulated Operation [Member] | Other Property Class [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		8.60%		11.80%		8.60%
Regulated Operation [Member] | Other Property Class [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.10%		2.90%		2.10%
Regulated Operation [Member] | Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 6,332.8		$ 6,200.8
Property, Plant and Equipment, Transmission		2,796.9		2,408.1
Property, Plant and Equipment, Distribution		3,569.1		3,402.5
Property, Plant and Equipment, Other		345.1		310.1
Property, Plant and Equipment, Construction Work in Progress		390.3		475.1
Accumulated Depreciation		3,631.5		3,395.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 9,802.7		$ 9,401.1
Regulated Operation [Member] | Appalachian Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.10%		3.10%		3.10%
Regulated Operation [Member] | Appalachian Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.50%		1.60%		1.70%
Regulated Operation [Member] | Appalachian Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		3.70%		3.60%		3.50%
Regulated Operation [Member] | Appalachian Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		6.00%		8.30%		6.90%
Regulated Operation [Member] | Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 4,056.1		$ 3,841.7
Property, Plant and Equipment, Transmission		1,472.8		1,406.9
Property, Plant and Equipment, Distribution		1,899.3		1,790.8
Property, Plant and Equipment, Other		507.7		511.6
Property, Plant and Equipment, Construction Work in Progress		654.2		519.8
Accumulated Depreciation		2,989.9		2,908.3
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 5,600.2		$ 5,162.5
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.40%		2.50%		2.00%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.70%		1.70%		1.70%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.80%		2.80%		2.80%
Regulated Operation [Member] | Indiana Michigan Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		8.60%		11.80%		6.10%
Regulated Operation [Member] | Ohio Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 0		$ 0
Property, Plant and Equipment, Transmission		2,319.2		2,235.6
Property, Plant and Equipment, Distribution		4,457.2		4,287.7
Property, Plant and Equipment, Other		433.4		397.8
Property, Plant and Equipment, Construction Work in Progress		221.5		171.9
Accumulated Depreciation		2,115.1		2,047.9
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 5,316.2		$ 5,045.1
Regulated Operation [Member] | Ohio Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.30%		2.30%		2.30%
Regulated Operation [Member] | Ohio Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.80%		2.80%		2.70%
Regulated Operation [Member] | Ohio Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		5.90%		7.20%		7.00%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation		$ 1,559.3		$ 1,302.6
Property, Plant and Equipment, Transmission		832.8		815.4
Property, Plant and Equipment, Distribution		2,322.4		2,206.7
Property, Plant and Equipment, Other		227.3		400.5
Property, Plant and Equipment, Construction Work in Progress		148.2		315.3
Accumulated Depreciation		1,272.7		1,352.5
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 3,817.3		$ 3,688
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.40%		1.70%		1.70%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.20%		1.90%		1.90%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.70%		2.50%		2.40%
Regulated Operation [Member] | Public Service Co Of Oklahoma [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		6.40%		4.60%		4.10%
Regulated Operation [Member] | Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
Property, Plant and Equipment, Generation	[20]	$ 4,607.6		$ 3,943.5
Property, Plant and Equipment, Transmission		1,584.2		1,387.8
Property, Plant and Equipment, Distribution		2,020.6		1,957.3
Property, Plant and Equipment, Other		399.3		582.2
Property, Plant and Equipment, Construction Work in Progress	[20]	113.7		744.7
Accumulated Depreciation		2,411.5		2,445
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 6,313.9		$ 6,170.5
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Generation [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.10%		2.20%		2.20%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.20%		2.30%		2.20%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.60%		2.60%		2.70%
Regulated Operation [Member] | Southwestern Electric Power Co [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		6.80%		5.50%		4.80%
Unregulated Operation [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 505.9		$ 4,020.3
Unregulated Operation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		66 years		66 years		66 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		55 years		55 years		55 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		50 years		0 years		0 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life	[21]	50 years		50 years		50 years
Unregulated Operation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Depreciable Life Ranges - Generation		40 years		35 years		35 years
Public Utilities, Property, Plant and Equipment, Transmission, Useful Life		43 years		43 years		43 years
Public Utilities, Property, Plant and Equipment, Distribution, Useful Life		40 years		0 years		0 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life	[21]	5 years		5 years		25 years
Unregulated Operation [Member] | Generation [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		17.20%		3.40%		3.40%
Unregulated Operation [Member] | Generation [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.80%		2.50%		2.60%
Unregulated Operation [Member] | Transmission [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		2.30%		2.30%		2.30%
Unregulated Operation [Member] | Distribution [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		1.30%		0.00%		0.00%
Unregulated Operation [Member] | Other Property Class [Member]
Depreciation, Depletion and Amortization
Annual Composite Depreciation Rate		9.10%		2.70%		17.10%
Unregulated Operation [Member] | Appalachian Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 23.1		$ 23.3
Unregulated Operation [Member] | Indiana Michigan Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		27.3		41
Unregulated Operation [Member] | Ohio Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9.4		9.6
Unregulated Operation [Member] | Public Service Co Of Oklahoma [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5.9		5.2
Unregulated Operation [Member] | Southwestern Electric Power Co [Member]
Depreciation, Depletion and Amortization
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		$ 115.6		150.6
Unregulated Operation [Member] | Southwestern Electric Power Co [Member] | Maximum [Member]
Depreciation, Depletion and Amortization
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		20 years
Unregulated Operation [Member] | Southwestern Electric Power Co [Member] | Minimum [Member]
Depreciation, Depletion and Amortization
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life		3 years
Muskingum River Plant [Member]
Asset Retirement Obligations (ARO)
Liabilities Settled		$ (81)
Tanners Creek Plant Units 1 Through 4 [Member]
Asset Retirement Obligations (ARO)
Liabilities Settled		(61)
Tanners Creek Plant Units 1 Through 4 [Member] | Indiana Michigan Power Co [Member]
Asset Retirement Obligations (ARO)
Liabilities Settled		(61)
Reduction in ARO Liability due to the execution of a joint use agreement with a third party [Member]
Asset Retirement Obligations (ARO)
Revisions in Cash Flow Estimates		20
Generation and Marketing [Member]
Depreciation, Depletion and Amortization
Accumulated Depreciation		42.2		3,367
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		322.5		$ 4,094.3
Property, Plant and Equipment (Textuals) [Abstract]
Property, Plant and Equipment -Assets Held for Sale		$ 1,756.2
[1]	Amount excludes $1.8 billion of Property, Plant and Equipment - Net classified as Assets Held for Sale on the balance sheet. See “Gavin, Waterford, Darby and Lawrenceburg Plants (Generation & Marketing Segment)” section of Note 7 for additional information.
[2]	Includes ARO related to Sabine and DHLC.
[3]	Includes ARO related to asbestos removal.
[4]	Includes ARO related to ash disposal facilities.
[5]	Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.24 billion and $1.18 billion as of December 31, 2016 and 2015, respectively.
[6]	Amount includes settlement of liabilities of $61 million associated with the sale of the Tanners Creek Plant site. See the “Tanners Creek” section of Note 7.
[7]	Amount includes settlement of liabilities of $81 million associated with the sale of the Muskingum River Plant site. See the “Muskingum River Plant” section of Note 7.
[8]	Amount includes a $20 million reduction in the ARO liability due to the execution of a joint use agreement with a third party.
[9]	In February 2017, AEP signed an agreement to purchase Dynegy Corporation’s ownership share of Conesville Generating Station, Unit 4. Simultaneously, AEP signed an agreement with Dynegy Corporation to sell AEP’s ownership share of the Wm. H. Zimmer Generating Station. The transactions are expected to close in the second quarter of 2017, subject to FERC approval and are not expected to have a material impact on net income, cash flows and financial condition.
[10]	Operated by AGR. See the “Impairments” section of Note 7.
[11]	Operated by Dayton Power & Light Company, a non-affiliated company. See the “Impairments” section of Note 7.
[12]	Operated by Dynegy Corporation, a non-affiliated company. See the “Impairments” section of Note 7.
[13]	Operated by CLECO, a non-affiliated company.
[14]	Operated by SWEPCo.
[15]	Operated by PSO, which owns 15.6%. Also jointly-owned (54.7%) by AEP Texas and various non-affiliated companies. See the “Impairments” section of Note 7.
[16]	Varying percentages of ownership.
[17]	AEGCo owns 50% of Unit 1 with I&M and 50% of capital additions for Unit 2.
[18]	Amounts include I&M’s 50% ownership of both Unit 1 and capital additions for Unit 2. Unit 2 is subject to an operating lease with a non-affiliated company. See the “Rockport Lease” section of Note 13.
[19]	Operated by I&M.
[20]	AEP and SWEPCo’s regulated generation and regulated CWIP include amounts related to SWEPCo’s Arkansas jurisdictional share of the Turk Plant.
[21]	SWEPCo’s nonregulated property, plant and equipment is depreciated using the straight-line method over a range of 3 to 20 years.

Unaudited Quarterly Financial78

Unaudited Quarterly Financial Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Summary of Unaudited Quarterly Financial Information
Total Revenues	$ 3,790.1		$ 4,652.2		$ 3,892.9		$ 4,044.9		$ 3,614.7		$ 4,431.4		$ 3,826.7		$ 4,580.4		$ 16,380.1	$ 16,453.2	$ 16,378.6
Operating Income (Loss)	575.9		(1,127.9)	[1]	866.2		892.9		466.4		960.2		804.1		1,102.8		1,207.1	3,333.5	3,127.4
Income (Loss) from Continuing Operations	375.2		(764.2)	[1]	506.4		503.1		205.2		511.8		431.4		620.2		620.5	1,768.6	1,590.5
Income (Loss) from Discontinued Operations, Net of Tax					(2.5)	[2]			265.5	[3]	7.8		(0.1)		10.5		(2.5)	283.7	47.5
Net Income (Loss)	375.2		(764.2)	[1]	503.9		503.1		470.7		519.6		431.3		630.7		618	2,052.3	1,638
Amounts Attributable to AEP Common Shareholders
Earnings (Loss) Attributable To AEP Common Shareholders	$ 373.4		$ (765.8)	[4]	$ 502.1		$ 501.2		$ 469.6		$ 518.3		$ 430		$ 629.2		$ 610.9	$ 2,047.1	$ 1,633.8
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations	$ 0.76	[5]	$ (1.56)	[4],[5]	$ 1.03	[5]	$ 1.02	[5]	$ 0.41	[5]	$ 1.04	[5]	$ 0.88	[5]	$ 1.27	[5]	$ 1.25	$ 3.59	$ 3.24
Basic Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations	0		0		(0.01)	[6]	0		0.54	[7]	0.02	[7]	0	[7]	0.02	[7]	(0.01)	0.58	0.10
Total Basic Earnings (Loss) Per Share Attributable to AEP Common Shareholders	0.76	[5]	(1.56)	[4],[5]	1.02	[5]	1.02	[5]	0.95	[5]	1.06	[5]	0.88	[5]	1.29	[5]	1.24	4.17	3.34
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders:
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Continuing Operations	0.76	[5]	(1.56)	[4],[5]	1.03	[5]	1.02	[5]	0.41	[5]	1.04	[5]	0.88	[5]	1.27	[5]	1.25	3.59	3.24
Diluted Earnings (Loss) per Share Attributable to AEP Common Shareholders from Discontinued Operations	0		0		(0.01)	[6]	0		0.54	[7]	0.02	[7]	0	[7]	0.02	[7]	(0.01)	0.58	0.10
Total Diluted Earnings (Loss) Per Share Attributable to AEP Common Shareholders	$ 0.76	[5]	$ (1.56)	[4],[5]	$ 1.02	[5]	$ 1.02	[5]	$ 0.95	[5]	$ 1.06	[5]	$ 0.88	[5]	$ 1.29	[5]	$ 1.24	$ 4.17	$ 3.34
Appalachian Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	$ 729.5		$ 778.2		$ 673.5		$ 820		$ 655		$ 727.5		$ 682		$ 899		$ 3,001.2	$ 2,963.5	$ 3,053.1
Operating Income (Loss)	136.2		204.4		158.3		244.4		133.7		157.9		145.7		273.5		743.3	710.8	568.2
Income (Loss) from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax					0				0		0		0		0
Net Income (Loss)	65.3		104.1		73.4		126.3		65.2		74.6		59		141.8		369.1	340.6	215.4
Indiana Michigan Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	514.9		597.6		522.4		532.7		487.3		568.3		544.3		586.3		2,167.6	2,186.2	2,249.7
Operating Income (Loss)	39.6		131.4		94.8		115.8		50.7		103.4		91.4		124.4		381.6	369.9	305.2
Income (Loss) from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax					0				0		0		0		0
Net Income (Loss)	38.5		75.4		51.3		74.7		24.9		56.6		50.6		72.7		239.9	204.8	155.6
Ohio Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	588.2		871.3		730.8		763.6		692.2		782.3		705.8		918.4		2,953.9	3,148.7	3,376.9
Operating Income (Loss)	64.3		171.6		138.6		134		100.5		140.9		96.5		122.9		508.5	460.8	433.5
Income (Loss) from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax					0				0		0		0		0
Net Income (Loss)	37.5		99.9		74.6		70.2		48		71.6		47.7		65.4		282.2	232.7	216.4
Public Service Co Of Oklahoma [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	273.6		401.7		300.2		274.3		292.6		420.3		319.5		306.8		1,249.8	1,339.2	1,351.6
Operating Income (Loss)	5.5		98.4		59		35.8		18.3		84.5		55.5		34.9		198.7	193.2	188.8
Income (Loss) from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax					0				0		0		0		0
Net Income (Loss)	2.6		52.8		28.9		15.7		7		44.7		27.1		13.7		100	92.5	86.9
Southwestern Electric Power Co [Member]
Summary of Unaudited Quarterly Financial Information
Total Revenues	402.3		539.7		427		379		378.6		532.5		438.1		431.7		1,748	1,780.9	1,846.4
Operating Income (Loss)	36.4		147.4		85.9		51.4		25.6		141.2		110.1		92.3		321.1	369.2	322.7
Income (Loss) from Continuing Operations	0		0		0		0		0		0		0		0
Income (Loss) from Discontinued Operations, Net of Tax					0				0		0		0		0
Net Income (Loss)	$ 16.5		$ 84.4		$ 44.3		$ 24.5		$ 7.7		$ 82.1		$ 59.5		$ 46.7		169.7	196	144.6
Amounts Attributable to AEP Common Shareholders
Earnings (Loss) Attributable To AEP Common Shareholders																	$ 165.6	$ 192.3	$ 140.4
[1]	Includes impairments for Merchant Generating Assets (see Note 7).
[2]	Includes final accounting adjustment for sale of AEPRO (see Note 7).
[3]	Includes sale of AEPRO (see Note 7).
[4]	Relates to impairments for Merchant Generating Assets (see Note 7).
[5]	Quarterly Earnings per Share amounts are intended to be stand-alone calculations and are not always additive to full-year amount due to rounding.
[6]	Relates to final accounting adjustment for sale of AEPRO (see Note 7).
[7]	Relates to sale of AEPRO (see Note 7).

Goodwill and Other Intangible79

Goodwill and Other Intangible Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Changes in Carrying Amount of Goodwill
Goodwill Total Balance	$ 52.5	$ 52.5	$ 91.3
Impairment Losses	0	0
Goodwill Written Off Related to Sale of AEPRO		(38.8)
Goodwill and Other Intangible Assets (Textuals) [Abstract]
Acquired Intangible Assets Subject to Amortization		2
Amortization of Intangible Assets	$ 2	3	5
Acquired Customer Contracts [Member]
Amortization Life, Gross Carrying Amount and Accumulated Amortization by Major Asset Class
Amortization Life	5 years
Gross Carrying Amount	$ 58.3	58.3
Accumulated Amortization	58.3	56.5
Corporate and Other [Member]
Changes in Carrying Amount of Goodwill
Goodwill Total Balance	37.1	37.1	75.9
Impairment Losses	0	0
Goodwill Written Off Related to Sale of AEPRO		(38.8)
Generation and Marketing [Member]
Changes in Carrying Amount of Goodwill
Goodwill Total Balance	15.4	15.4	$ 15.4
Impairment Losses	$ 0	0
Goodwill Written Off Related to Sale of AEPRO		$ 0