Appalachian Power 10-Q25 Apr 142014 Q1 Quarterly reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
Document and Entity Information	Mar. 31, 2014	Apr. 23, 2014
Entity Registrant Name	'AMERICAN ELECTRIC POWER CO INC	'
Entity Central Index Key	'0000004904	'
Document Type	'10-Q	'
Document Period End Date	31-Mar-14	'
Amendment Flag	'false	'
Document Fiscal Year Focus	'2014	'
Document Fiscal Period Focus	'Q1	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Large Accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	488,083,018
Appalachian Power Co [Member]	'	'
Entity Registrant Name	'APPALACHIAN POWER CO	'
Entity Central Index Key	'0000006879	'
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	'0000050172	'
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	'0000073986	'
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	'0000081027	'
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	'0000092487	'
Entity Filer Category	'Non-accelerated Filer	'
Entity Common Stock, Shares Outstanding	'	7,536,640

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	3 Months Ended
Consolidated Statements of Income (USD $)	Mar. 31, 2014	Mar. 31, 2013
Revenues	'	'
Vertically Integrated Utilities	$2,549,000,000	$2,356,000,000
Transmission and Distribution Utilities	1,161,000,000	1,090,000,000
Generation and Marketing	821,000,000	258,000,000
Other Revenues	117,000,000	122,000,000
TOTAL REVENUES	4,648,000,000	3,826,000,000
Expenses	'	'
Fuel and Other Consumables Used for Electric Generation	1,168,000,000	1,031,000,000
Purchased Electricity for Resale	638,000,000	371,000,000
Other Operation	780,000,000	738,000,000
Maintenance	292,000,000	293,000,000
Depreciation and Amortization	491,000,000	420,000,000
Taxes Other Than Income Taxes	238,000,000	218,000,000
TOTAL EXPENSES	3,607,000,000	3,071,000,000
OPERATING INCOME (LOSS)	1,041,000,000	755,000,000
Other Income (Expense):	'	'
Interest and Investment Income	1,000,000	3,000,000
Carrying Costs Income	6,000,000	4,000,000
Allowance for Equity Funds Used During Construction	22,000,000	15,000,000
Interest Expense	-220,000,000	-232,000,000
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	850,000,000	545,000,000
Income Tax Expense (Credit)	307,000,000	195,000,000
Equity Earnings (Loss) of Unconsolidated Subsidiaries	18,000,000	14,000,000
NET INCOME (LOSS)	561,000,000	364,000,000
Net Income Attributable to Noncontrolling Interests	1,000,000	1,000,000
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	560,000,000	363,000,000
Earnings Per Share	'	'
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	487,867,089	485,823,668
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$1.15	$0.75
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	488,271,167	486,344,036
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$1.15	$0.75
CASH DIVIDENDS DECLARED PER SHARE	$0.50	$0.47
Appalachian Power Co [Member]	'	'
Revenues	'	'
Vertically Integrated Utilities	866,457,000	872,732,000
Sales to AEP Affiliates	44,914,000	76,860,000
Other Revenues	2,020,000	1,902,000
TOTAL REVENUES	913,391,000	951,494,000
Expenses	'	'
Fuel and Other Consumables Used for Electric Generation	230,737,000	204,939,000
Purchased Electricity for Resale	168,991,000	65,456,000
Purchased Electricity from AEP Affiliates	4,662,000	222,942,000
Other Operation	93,538,000	78,908,000
Maintenance	60,090,000	99,386,000
Depreciation and Amortization	104,586,000	87,903,000
Taxes Other Than Income Taxes	30,777,000	27,400,000
TOTAL EXPENSES	693,381,000	786,934,000
OPERATING INCOME (LOSS)	220,010,000	164,560,000
Other Income (Expense):	'	'
Interest Income	401,000	331,000
Carrying Costs Income	-1,875,000	103,000
Allowance for Equity Funds Used During Construction	1,235,000	770,000
Interest Expense	-51,672,000	-48,204,000
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	168,099,000	117,560,000
Income Tax Expense (Credit)	66,248,000	47,012,000
NET INCOME (LOSS)	101,851,000	70,548,000
Indiana Michigan Power Co [Member]	'	'
Revenues	'	'
Vertically Integrated Utilities	614,843,000	490,603,000
Sales to AEP Affiliates	2,284,000	54,977,000
Other Revenues - Affiliated	24,727,000	35,825,000
Other Revenues	0	1,988,000
TOTAL REVENUES	641,854,000	583,393,000
Expenses	'	'
Fuel and Other Consumables Used for Electric Generation	156,643,000	104,865,000
Purchased Electricity for Resale	5,362,000	41,812,000
Purchased Electricity from AEP Affiliates	72,056,000	101,376,000
Other Operation	141,350,000	145,238,000
Maintenance	48,565,000	45,514,000
Depreciation and Amortization	50,031,000	40,902,000
Taxes Other Than Income Taxes	21,823,000	22,456,000
TOTAL EXPENSES	495,830,000	502,163,000
OPERATING INCOME (LOSS)	146,024,000	81,230,000
Other Income (Expense):	'	'
Interest Income	1,049,000	2,055,000
Allowance for Equity Funds Used During Construction	3,964,000	5,646,000
Interest Expense	-25,633,000	-24,211,000
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	125,404,000	64,720,000
Income Tax Expense (Credit)	38,315,000	21,263,000
NET INCOME (LOSS)	87,089,000	43,457,000
Ohio Power Co [Member]	'	'
Revenues	'	'
Transmission and Distribution Utilities	846,906,000	933,681,000
Sales to AEP Affiliates	31,978,000	285,642,000
Other Revenues - Affiliated	0	7,840,000
Other Revenues	1,308,000	6,627,000
TOTAL REVENUES	880,192,000	1,233,790,000
Expenses	'	'
Fuel and Other Consumables Used for Electric Generation	0	409,584,000
Purchased Electricity for Resale	79,130,000	43,185,000
Purchased Electricity from AEP Affiliates	314,124,000	80,381,000
Other Operation	151,426,000	184,187,000
Maintenance	34,651,000	74,295,000
Depreciation and Amortization	58,699,000	92,324,000
Amortization of Generation Deferrals	31,186,000	0
Taxes Other Than Income Taxes	95,257,000	105,021,000
TOTAL EXPENSES	764,473,000	988,977,000
OPERATING INCOME (LOSS)	115,719,000	244,813,000
Other Income (Expense):	'	'
Interest Income	3,274,000	363,000
Carrying Costs Income	7,114,000	3,263,000
Allowance for Equity Funds Used During Construction	1,726,000	1,304,000
Interest Expense	-33,007,000	-50,173,000
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	94,826,000	199,570,000
Income Tax Expense (Credit)	34,052,000	69,796,000
NET INCOME (LOSS)	60,774,000	129,774,000
Public Service Co Of Oklahoma [Member]	'	'
Revenues	'	'
Vertically Integrated Utilities	296,710,000	259,903,000
Sales to AEP Affiliates	4,597,000	1,834,000
Other Revenues	78,000	552,000
TOTAL REVENUES	301,385,000	262,289,000
Expenses	'	'
Fuel and Other Consumables Used for Electric Generation	65,937,000	43,310,000
Purchased Electricity for Resale	79,691,000	64,655,000
Purchased Electricity from AEP Affiliates	11,024,000	10,216,000
Other Operation	58,711,000	47,807,000
Maintenance	24,745,000	28,572,000
Depreciation and Amortization	23,982,000	24,180,000
Taxes Other Than Income Taxes	11,969,000	9,997,000
TOTAL EXPENSES	276,059,000	228,737,000
OPERATING INCOME (LOSS)	25,326,000	33,552,000
Other Income (Expense):	'	'
Allowance for Equity Funds Used During Construction	1,431,000	980,000
Other Income	1,428,000	2,115,000
Interest Expense	-13,317,000	-13,340,000
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	13,437,000	22,327,000
Income Tax Expense (Credit)	4,989,000	8,634,000
NET INCOME (LOSS)	8,448,000	13,693,000
Southwestern Electric Power Co [Member]	'	'
Revenues	'	'
Vertically Integrated Utilities	426,627,000	381,277,000
Sales to AEP Affiliates	13,598,000	12,709,000
Other Revenues	365,000	331,000
TOTAL REVENUES	440,590,000	394,317,000
Expenses	'	'
Fuel and Other Consumables Used for Electric Generation	145,587,000	151,358,000
Purchased Electricity for Resale	61,165,000	39,760,000
Purchased Electricity from AEP Affiliates	3,766,000	1,017,000
Other Operation	68,537,000	59,448,000
Maintenance	30,411,000	27,791,000
Depreciation and Amortization	45,661,000	44,882,000
Taxes Other Than Income Taxes	20,737,000	19,422,000
TOTAL EXPENSES	375,864,000	343,678,000
OPERATING INCOME (LOSS)	64,726,000	50,639,000
Other Income (Expense):	'	'
Allowance for Equity Funds Used During Construction	2,081,000	1,024,000
Other Income	1,967,000	1,054,000
Interest Expense	-31,876,000	-33,990,000
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	34,817,000	17,703,000
Income Tax Expense (Credit)	12,165,000	6,796,000
Equity Earnings (Loss) of Unconsolidated Subsidiaries	310,000	641,000
NET INCOME (LOSS)	22,962,000	11,548,000
Net Income Attributable to Noncontrolling Interests	1,102,000	1,090,000
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$21,860,000	$10,458,000

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (Loss) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Net Income (Loss)	$561,000,000	$364,000,000
OTHER COMPREHENSIVE INCOME	'	'
Cash Flow Hedges, Net of Tax	5,000,000	24,000,000
Securities Available for Sale, Net of Tax	0	1,000,000
Amortization of Pension and OPEB Deferred Costs, Net of Tax	1,000,000	6,000,000
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	6,000,000	31,000,000
TOTAL COMPREHENSIVE INCOME (LOSS)	567,000,000	395,000,000
Total Comprehensive Income Attributable to Noncontrolling Interest	1,000,000	1,000,000
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	566,000,000	394,000,000
Appalachian Power Co [Member]	'	'
Net Income (Loss)	101,851,000	70,548,000
OTHER COMPREHENSIVE INCOME	'	'
Cash Flow Hedges, Net of Tax	246,000	1,258,000
Amortization of Pension and OPEB Deferred Costs, Net of Tax	-333,000	358,000
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	-87,000	1,616,000
TOTAL COMPREHENSIVE INCOME (LOSS)	101,764,000	72,164,000
Indiana Michigan Power Co [Member]	'	'
Net Income (Loss)	87,089,000	43,457,000
OTHER COMPREHENSIVE INCOME	'	'
Cash Flow Hedges, Net of Tax	425,000	3,123,000
Amortization of Pension and OPEB Deferred Costs, Net of Tax	43,000	176,000
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	468,000	3,299,000
TOTAL COMPREHENSIVE INCOME (LOSS)	87,557,000	46,756,000
Ohio Power Co [Member]	'	'
Net Income (Loss)	60,774,000	129,774,000
OTHER COMPREHENSIVE INCOME	'	'
Cash Flow Hedges, Net of Tax	-448,000	1,066,000
Amortization of Pension and OPEB Deferred Costs, Net of Tax	0	3,269,000
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	-448,000	4,335,000
TOTAL COMPREHENSIVE INCOME (LOSS)	60,326,000	134,109,000
Public Service Co Of Oklahoma [Member]	'	'
Net Income (Loss)	8,448,000	13,693,000
OTHER COMPREHENSIVE INCOME	'	'
Cash Flow Hedges, Net of Tax	-246,000	-167,000
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	-246,000	-167,000
TOTAL COMPREHENSIVE INCOME (LOSS)	8,202,000	13,526,000
Southwestern Electric Power Co [Member]	'	'
Net Income (Loss)	22,962,000	11,548,000
OTHER COMPREHENSIVE INCOME	'	'
Cash Flow Hedges, Net of Tax	502,000	596,000
Amortization of Pension and OPEB Deferred Costs, Net of Tax	-234,000	-63,000
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	268,000	533,000
TOTAL COMPREHENSIVE INCOME (LOSS)	23,230,000	12,081,000
Total Comprehensive Income Attributable to Noncontrolling Interest	1,102,000	1,090,000
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$22,128,000	$10,991,000

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Cash Flow Hedges, Tax	$3,000,000	$13,000,000
Securities Available for Sale, Tax	0	1,000,000
Amortization of Pension and OPEB Deferred Costs, Tax	0	3,000,000
Appalachian Power Co [Member]	'	'
Cash Flow Hedges, Tax	132,000	677,000
Amortization of Pension and OPEB Deferred Costs, Tax	-179,000	193,000
Indiana Michigan Power Co [Member]	'	'
Cash Flow Hedges, Tax	229,000	1,682,000
Amortization of Pension and OPEB Deferred Costs, Tax	23,000	94,000
Ohio Power Co [Member]	'	'
Cash Flow Hedges, Tax	-241,000	574,000
Amortization of Pension and OPEB Deferred Costs, Tax	0	1,760,000
Public Service Co Of Oklahoma [Member]	'	'
Cash Flow Hedges, Tax	-132,000	-90,000
Southwestern Electric Power Co [Member]	'	'
Cash Flow Hedges, Tax	270,000	321,000
Amortization of Pension and OPEB Deferred Costs, Tax	($126,000)	($34,000)

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Changes in Equity (USD $)

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]

Additional Paid-in Capital [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Income [Member]

Noncontrolling Interests [Member]

Appalachian Power Co [Member]

Indiana Michigan Power Co [Member]

Ohio Power Co [Member]

Public Service Co Of Oklahoma [Member]

Southwestern Electric Power Co [Member]

Appalachian Power Co [Member]

Indiana Michigan Power Co [Member]

Ohio Power Co [Member]

Public Service Co Of Oklahoma [Member]

Southwestern Electric Power Co [Member]

Appalachian Power Co [Member]

Indiana Michigan Power Co [Member]

Ohio Power Co [Member]

Public Service Co Of Oklahoma [Member]

Southwestern Electric Power Co [Member]

Appalachian Power Co [Member]

Indiana Michigan Power Co [Member]

Ohio Power Co [Member]

Public Service Co Of Oklahoma [Member]

Southwestern Electric Power Co [Member]

Beginning Balance at Dec. 31, 2012

$15,237,000,000

$3,052,562,000

$1,803,775,000

$4,525,709,000

$916,278,000

$2,021,473,000

$3,289,000,000

$260,458,000

$56,584,000

$321,201,000

$157,230,000

$135,660,000

$6,049,000,000

$1,573,752,000

$980,896,000

$1,744,099,000

$364,037,000

$674,606,000

$6,236,000,000

$1,248,250,000

$795,178,000

$2,626,134,000

$388,530,000

$1,228,806,000

($337,000,000)

($29,898,000)

($28,883,000)

($165,725,000)

$6,481,000

($17,860,000)

$261,000

Beginning Balance, Shares at Dec. 31, 2012

506,000,000

Issuance of Common Stock, Value

15,000,000

2,000,000

13,000,000

Issuance of Common Stock, Shares

Common Stock Dividends

-50,000,000

-12,500,000

-75,000,000

-13,750,000

31,250,000

-50,000,000

-12,500,000

-75,000,000

-13,750,000

31,250,000

Common Stock Dividends

-230,000,000

-964,000

-229,000,000

-1,000,000

-964,000

Other Changes in Equity

4,000,000

Net Income (Loss)

363,000,000

10,458,000

Net Income (Loss) Attributable to Noncontrolling Interests

1,000,000

1,090,000

1,000,000

1,090,000

Net Income (Loss)

364,000,000

70,548,000

43,457,000

129,774,000

13,693,000

11,548,000

70,548,000

43,457,000

129,774,000

13,693,000

Other Comprehensive Income (Loss)

31,000,000

1,616,000

3,299,000

4,335,000

-167,000

533,000

31,000,000

1,616,000

3,299,000

4,335,000

-167,000

533,000

Ending Balance at Mar. 31, 2013

15,421,000,000

3,074,726,000

1,838,031,000

4,584,818,000

916,054,000

2,001,340,000

3,291,000,000

260,458,000

56,584,000

321,201,000

157,230,000

135,660,000

6,066,000,000

1,573,752,000

980,896,000

1,744,099,000

364,037,000

674,606,000

6,370,000,000

1,268,798,000

826,135,000

2,680,908,000

388,473,000

1,208,014,000

-306,000,000

-28,282,000

-25,584,000

-161,390,000

6,314,000

-17,327,000

387,000

Ending Balance, Shares at Mar. 31, 2013

506,000,000

Beginning Balance at Dec. 31, 2013

16,086,000,000

3,229,432,000

1,922,153,000

1,625,265,000

942,101,000

2,055,917,000

3,303,000,000

260,458,000

56,584,000

321,201,000

157,230,000

135,660,000

6,131,000,000

1,809,562,000

980,896,000

663,782,000

364,037,000

674,606,000

6,766,000,000

1,156,461,000

900,182,000

633,203,000

415,076,000

1,253,617,000

-115,000,000

2,951,000

-15,509,000

7,079,000

5,758,000

-8,444,000

1,000,000

478,000

Beginning Balance, Shares at Dec. 31, 2013

508,113,964

10,482,000

Issuance of Common Stock, Value

15,000,000

2,000,000

13,000,000

Issuance of Common Stock, Shares

Common Stock Dividends

-20,000,000

-25,000,000

-20,000,000

-25,000,000

Common Stock Dividends

-245,000,000

-1,236,000

-244,000,000

-1,000,000

-1,236,000

Other Changes in Equity

-4,000,000

-6,000,000

2,000,000

Net Income (Loss)

560,000,000

21,860,000

Net Income (Loss) Attributable to Noncontrolling Interests

1,000,000

1,102,000

1,000,000

1,102,000

Net Income (Loss)

561,000,000

101,851,000

87,089,000

60,774,000

8,448,000

22,962,000

101,851,000

87,089,000

60,774,000

8,448,000

Other Comprehensive Income (Loss)

6,000,000

-87,000

468,000

-448,000

-246,000

268,000

6,000,000

-87,000

468,000

-448,000

-246,000

268,000

Ending Balance at Mar. 31, 2014

$16,419,000,000

$3,311,196,000

$1,984,710,000

$1,660,591,000

$950,303,000

$2,052,911,000

$3,305,000,000

$260,458,000

$56,584,000

$321,201,000

$157,230,000

$135,660,000

$6,144,000,000

$1,809,562,000

$980,896,000

$663,782,000

$364,037,000

$674,606,000

$7,076,000,000

$1,238,312,000

$962,271,000

$668,977,000

$423,524,000

$1,250,477,000

($109,000,000)

$2,864,000

($15,041,000)

$6,631,000

$5,512,000

($8,176,000)

$3,000,000

$344,000

Ending Balance, Shares at Mar. 31, 2014

508,397,086

10,482,000

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Mar. 31, 2014		Dec. 31, 2013
Current Assets	'		'
Cash and Cash Equivalents	$292,000,000		$118,000,000
Other Temporary Investments	310,000,000		353,000,000
Accounts Receivable:	'		'
Customers	785,000,000		746,000,000
Accrued Unbilled Revenues	143,000,000		157,000,000
Pledged Accounts Receivable - AEP Credit	1,015,000,000		945,000,000
Miscellaneous	66,000,000		72,000,000
Allowance for Uncollectible Accounts	-66,000,000		-60,000,000
Total Accounts Receivable	1,943,000,000		1,860,000,000
Fuel	490,000,000		701,000,000
Materials and Supplies	724,000,000		722,000,000
Risk Management Assets	125,000,000		160,000,000
Regulatory Asset for Under-Recovered Fuel Costs	175,000,000		80,000,000
Margin Deposits	117,000,000		70,000,000
Prepayments and Other Current Assets	159,000,000		246,000,000
TOTAL CURRENT ASSETS	4,335,000,000		4,310,000,000
Property, Plant and Equipment	'		'
Generation	25,174,000,000		25,074,000,000
Transmission	11,014,000,000		10,893,000,000
Distribution	16,518,000,000		16,377,000,000
Other Property, Plant and Equipment	5,552,000,000		5,470,000,000
Construction Work in Progress	2,836,000,000		2,471,000,000
Total Property, Plant and Equipment	61,094,000,000		60,285,000,000
Accumulated Depreciation and Amortization	19,564,000,000		19,288,000,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	41,530,000,000		40,997,000,000
Other Noncurrent Assets	'		'
Regulatory Assets	4,384,000,000		4,376,000,000
Securitized Assets	2,308,000,000		2,373,000,000
Spent Nuclear Fuel and Decommissioning Trusts	1,962,000,000		1,932,000,000
Goodwill	91,000,000		91,000,000
Long-term Risk Management Assets	266,000,000		297,000,000
Deferred Charges and Other Noncurrent Assets	2,162,000,000		2,038,000,000
TOTAL OTHER NONCURRENT ASSETS	11,173,000,000		11,107,000,000
TOTAL ASSETS	57,038,000,000		56,414,000,000
Current Liabilities	'		'
Accounts Payable	1,213,000,000		1,266,000,000
Short-term Debt:	'		'
Securitized Debt for Receivable - AEP Credit	700,000,000	[1]	700,000,000	[1]
Other Short-term Debt	632,000,000		57,000,000
Total Short-term Debt	1,332,000,000		757,000,000
Long-term Debt Due Within One Year	1,612,000,000		1,549,000,000
Risk Management Liabilities	60,000,000		90,000,000
Customer Deposits	302,000,000		299,000,000
Accrued Taxes	803,000,000		822,000,000
Accrued Interest	220,000,000		245,000,000
Regulatory Liability for Over-Recovered Fuel Costs	60,000,000		119,000,000
Other Current Liabilities	917,000,000		965,000,000
TOTAL CURRENT LIABILITIES	6,519,000,000		6,112,000,000
Noncurrent Liabilities	'		'
Long-term Debt	16,475,000,000		16,828,000,000
Long-term Risk Management Liabilities	137,000,000		177,000,000
Deferred Income Taxes	10,446,000,000		10,300,000,000
Regulatory Liabilities and Deferred Investment Tax Credits	3,765,000,000		3,694,000,000
Asset Retirement Obligations	1,853,000,000		1,835,000,000
Employee Benefits and Pension Obligations	456,000,000		415,000,000
Deferred Credits and Other Noncurrent Liabilities	968,000,000		967,000,000
TOTAL NONCURRENT LIABILITIES	34,100,000,000		34,216,000,000
TOTAL LIABILITIES	40,619,000,000		40,328,000,000
Rate Matters	'		'
Commitments and Contingencies	'		'
Equity	'		'
Common Stock	3,305,000,000		3,303,000,000
Paid-in Capital	6,144,000,000		6,131,000,000
Retained Earnings	7,076,000,000		6,766,000,000
Accumulated Other Comprehensive Income (Loss)	-109,000,000		-115,000,000
TOTAL COMMON SHAREHOLDER'S EQUITY	16,416,000,000		16,085,000,000
Noncontrolling Interests	3,000,000		1,000,000
TOTAL EQUITY	16,419,000,000		16,086,000,000
TOTAL LIABILITIES AND EQUITY	57,038,000,000		56,414,000,000
Appalachian Power Co [Member]	'		'
Current Assets	'		'
Cash and Cash Equivalents	4,758,000		2,745,000
Advances to Affiliates	245,516,000		92,485,000
Accounts Receivable:	'		'
Customers	150,954,000		142,010,000
Affiliated Companies	72,283,000		113,793,000
Accrued Unbilled Revenues	46,631,000		55,930,000
Miscellaneous	472,000		412,000
Allowance for Uncollectible Accounts	-3,517,000		-2,443,000
Total Accounts Receivable	266,823,000		309,702,000
Fuel	103,983,000		191,811,000
Materials and Supplies	128,614,000		128,843,000
Risk Management Assets	15,972,000		21,171,000
Regulatory Asset for Under-Recovered Fuel Costs	79,498,000		39,811,000
Prepayments and Other Current Assets	33,677,000		16,472,000
TOTAL CURRENT ASSETS	878,841,000		803,040,000
Property, Plant and Equipment	'		'
Generation	6,752,422,000		6,745,172,000
Transmission	2,173,839,000		2,160,660,000
Distribution	3,161,917,000		3,139,150,000
Other Property, Plant and Equipment	365,750,000		357,517,000
Construction Work in Progress	217,713,000		184,701,000
Total Property, Plant and Equipment	12,671,641,000		12,587,200,000
Accumulated Depreciation and Amortization	3,679,394,000		3,617,990,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	8,992,247,000		8,969,210,000
Other Noncurrent Assets	'		'
Regulatory Assets	1,006,426,000		1,003,890,000
Securitized Assets	364,984,000		369,355,000
Long-term Risk Management Assets	14,013,000		16,948,000
Deferred Charges and Other Noncurrent Assets	157,592,000		148,205,000
TOTAL OTHER NONCURRENT ASSETS	1,543,015,000		1,538,398,000
TOTAL ASSETS	11,414,103,000		11,310,648,000
Current Liabilities	'		'
Accounts Payable	188,773,000		169,184,000
Affiliated Companies	87,447,000		120,789,000
Short-term Debt:	'		'
Long-term Debt Due Within One Year	553,399,000		342,360,000
Risk Management Liabilities	4,636,000		8,892,000
Customer Deposits	69,180,000		66,040,000
Deferred Income Taxes	12,208,000		6,899,000
Accrued Taxes	115,557,000		114,699,000
Accrued Interest	62,397,000		51,899,000
Regulatory Liability for Over-Recovered Fuel Costs	45,144,000		107,048,000
Other Current Liabilities	76,445,000		97,566,000
TOTAL CURRENT LIABILITIES	1,215,186,000		1,085,376,000
Noncurrent Liabilities	'		'
Long-term Debt	3,555,117,000		3,765,997,000
Long-term Debt - Affiliated	86,000,000		86,000,000
Long-term Risk Management Liabilities	7,929,000		10,241,000
Deferred Income Taxes	2,297,662,000		2,232,441,000
Regulatory Liabilities and Deferred Investment Tax Credits	648,895,000		631,225,000
Employee Benefits and Pension Obligations	105,927,000		82,264,000
Deferred Credits and Other Noncurrent Liabilities	186,191,000		187,672,000
TOTAL NONCURRENT LIABILITIES	6,887,721,000		6,995,840,000
TOTAL LIABILITIES	8,102,907,000		8,081,216,000
Rate Matters	'		'
Commitments and Contingencies	'		'
Equity	'		'
Common Stock	260,458,000		260,458,000
Paid-in Capital	1,809,562,000		1,809,562,000
Retained Earnings	1,238,312,000		1,156,461,000
Accumulated Other Comprehensive Income (Loss)	2,864,000		2,951,000
TOTAL EQUITY	3,311,196,000		3,229,432,000
TOTAL LIABILITIES AND EQUITY	11,414,103,000		11,310,648,000
Indiana Michigan Power Co [Member]	'		'
Current Assets	'		'
Cash and Cash Equivalents	2,288,000		1,317,000
Advances to Affiliates	59,162,000		55,863,000
Accounts Receivable:	'		'
Customers	52,471,000		63,011,000
Affiliated Companies	71,359,000		78,282,000
Accrued Unbilled Revenues	13,999,000		17,293,000
Miscellaneous	1,259,000		5,064,000
Allowance for Uncollectible Accounts	-33,000		-184,000
Total Accounts Receivable	139,055,000		163,466,000
Fuel	49,365,000		53,807,000
Materials and Supplies	206,820,000		209,718,000
Risk Management Assets	12,558,000		15,388,000
Accrued Tax Benefits	29,792,000		48,832,000
Prepayments and Other Current Assets	27,897,000		38,103,000
TOTAL CURRENT ASSETS	526,937,000		586,494,000
Property, Plant and Equipment	'		'
Generation	3,583,883,000		3,577,906,000
Transmission	1,310,169,000		1,304,225,000
Distribution	1,641,866,000		1,625,057,000
Other Property, Plant and Equipment	1,440,408,000		1,421,361,000
Construction Work in Progress	476,734,000		427,164,000
Total Property, Plant and Equipment	8,453,060,000		8,355,713,000
Accumulated Depreciation and Amortization	3,337,401,000		3,299,349,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	5,115,659,000		5,056,364,000
Other Noncurrent Assets	'		'
Regulatory Assets	505,750,000		524,114,000
Spent Nuclear Fuel and Decommissioning Trusts	1,962,151,000		1,931,610,000
Long-term Risk Management Assets	9,505,000		11,495,000
Deferred Charges and Other Noncurrent Assets	140,198,000		143,657,000
TOTAL OTHER NONCURRENT ASSETS	2,617,604,000		2,610,876,000
TOTAL ASSETS	8,260,200,000		8,253,734,000
Current Liabilities	'		'
Accounts Payable	121,516,000		142,219,000
Affiliated Companies	69,635,000		93,773,000
Short-term Debt:	'		'
Long-term Debt Due Within One Year	287,598,000		294,845,000
Risk Management Liabilities	4,134,000		7,029,000
Customer Deposits	31,851,000		31,103,000
Accrued Taxes	83,314,000		73,292,000
Accrued Interest	15,182,000		27,686,000
Obligations Under Capital Leases	48,407,000		46,210,000
Other Current Liabilities	146,801,000		139,088,000
TOTAL CURRENT LIABILITIES	808,438,000		855,245,000
Noncurrent Liabilities	'		'
Long-term Debt	1,725,246,000		1,744,171,000
Long-term Risk Management Liabilities	5,378,000		6,946,000
Deferred Income Taxes	1,184,213,000		1,183,350,000
Regulatory Liabilities and Deferred Investment Tax Credits	1,122,812,000		1,112,645,000
Asset Retirement Obligations	1,269,671,000		1,255,184,000
Deferred Credits and Other Noncurrent Liabilities	159,732,000		174,040,000
TOTAL NONCURRENT LIABILITIES	5,467,052,000		5,476,336,000
TOTAL LIABILITIES	6,275,490,000		6,331,581,000
Rate Matters	'		'
Commitments and Contingencies	'		'
Equity	'		'
Common Stock	56,584,000		56,584,000
Paid-in Capital	980,896,000		980,896,000
Retained Earnings	962,271,000		900,182,000
Accumulated Other Comprehensive Income (Loss)	-15,041,000		-15,509,000
TOTAL EQUITY	1,984,710,000		1,922,153,000
TOTAL LIABILITIES AND EQUITY	8,260,200,000		8,253,734,000
Ohio Power Co [Member]	'		'
Current Assets	'		'
Cash and Cash Equivalents	4,780,000		3,004,000
Restricted Cash for Securitized Funding	32,054,000		19,387,000
Advances to Affiliates	0		339,070,000
Accounts Receivable:	'		'
Customers	96,218,000		67,054,000
Affiliated Companies	72,311,000		74,771,000
Accrued Unbilled Revenues	49,761,000		36,353,000
Miscellaneous	747,000		1,559,000
Allowance for Uncollectible Accounts	-39,602,000		-34,984,000
Total Accounts Receivable	179,435,000		144,753,000
Notes Receivable Due Within One Year - Affiliated	178,580,000		178,580,000
Materials and Supplies	55,311,000		53,711,000
Risk Management Assets	3,980,000		3,082,000
Deferred Income Tax Benefits	33,642,000		36,105,000
Accrued Tax Benefits	487,000		7,109,000
Regulatory Asset for Under-Recovered Fuel Costs	26,153,000		15,829,000
Prepayments and Other Current Assets	7,085,000		6,483,000
TOTAL CURRENT ASSETS	521,507,000		807,113,000
Property, Plant and Equipment	'		'
Transmission	2,030,881,000		2,011,289,000
Distribution	3,907,852,000		3,877,532,000
Other Property, Plant and Equipment	379,780,000		364,573,000
Construction Work in Progress	188,636,000		185,428,000
Total Property, Plant and Equipment	6,507,149,000		6,438,822,000
Accumulated Depreciation and Amortization	1,986,318,000		1,973,042,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	4,520,831,000		4,465,780,000
Other Noncurrent Assets	'		'
Notes Receivable - Affiliated	118,245,000		118,245,000
Regulatory Assets	1,398,055,000		1,378,697,000
Securitized Assets	126,597,000		131,582,000
Deferred Charges and Other Noncurrent Assets	211,819,000		260,141,000
TOTAL OTHER NONCURRENT ASSETS	1,854,716,000		1,888,665,000
TOTAL ASSETS	6,897,054,000		7,161,558,000
Current Liabilities	'		'
Advances from Affiliates	27,108,000		0
Accounts Payable	128,333,000		146,307,000
Affiliated Companies	195,954,000		222,889,000
Short-term Debt:	'		'
Long-term Debt Due Within One Year	235,785,000		438,595,000
Accrued Taxes	324,491,000		429,260,000
Accrued Interest	49,854,000		40,853,000
Other Current Liabilities	128,143,000		144,334,000
TOTAL CURRENT LIABILITIES	1,089,668,000		1,422,238,000
Noncurrent Liabilities	'		'
Long-term Debt	2,274,500,000		2,296,580,000
Deferred Income Taxes	1,352,301,000		1,330,711,000
Regulatory Liabilities and Deferred Investment Tax Credits	467,433,000		435,499,000
Employee Benefits and Pension Obligations	28,789,000		28,329,000
Deferred Credits and Other Noncurrent Liabilities	23,772,000		22,936,000
TOTAL NONCURRENT LIABILITIES	4,146,795,000		4,114,055,000
TOTAL LIABILITIES	5,236,463,000		5,536,293,000
Rate Matters	'		'
Commitments and Contingencies	'		'
Equity	'		'
Common Stock	321,201,000		321,201,000
Paid-in Capital	663,782,000		663,782,000
Retained Earnings	668,977,000		633,203,000
Accumulated Other Comprehensive Income (Loss)	6,631,000		7,079,000
TOTAL EQUITY	1,660,591,000		1,625,265,000
TOTAL LIABILITIES AND EQUITY	6,897,054,000		7,161,558,000
Public Service Co Of Oklahoma [Member]	'		'
Current Assets	'		'
Cash and Cash Equivalents	1,756,000		1,277,000
Accounts Receivable:	'		'
Customers	29,384,000		32,314,000
Affiliated Companies	18,634,000		30,392,000
Miscellaneous	3,460,000		3,102,000
Allowance for Uncollectible Accounts	-325,000		-462,000
Total Accounts Receivable	51,153,000		65,346,000
Fuel	15,054,000		15,191,000
Materials and Supplies	52,695,000		52,707,000
Risk Management Assets	1,349,000		1,167,000
Deferred Income Tax Benefits	0		7,333,000
Accrued Tax Benefits	35,708,000		21,665,000
Regulatory Asset for Under-Recovered Fuel Costs	26,692,000		3,298,000
Prepayments and Other Current Assets	5,994,000		6,194,000
TOTAL CURRENT ASSETS	190,401,000		174,178,000
Property, Plant and Equipment	'		'
Generation	1,236,105,000		1,203,221,000
Transmission	727,512,000		731,312,000
Distribution	2,001,049,000		1,986,032,000
Other Property, Plant and Equipment	411,700,000		393,026,000
Construction Work in Progress	172,949,000		175,890,000
Total Property, Plant and Equipment	4,549,315,000		4,489,481,000
Accumulated Depreciation and Amortization	1,334,507,000		1,323,522,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	3,214,808,000		3,165,959,000
Other Noncurrent Assets	'		'
Regulatory Assets	164,929,000		156,690,000
Employee Benefits and Pension Assets	23,162,000		22,629,000
Deferred Charges and Other Noncurrent Assets	38,197,000		7,238,000
TOTAL OTHER NONCURRENT ASSETS	226,288,000		186,557,000
TOTAL ASSETS	3,631,497,000		3,526,694,000
Current Liabilities	'		'
Advances from Affiliates	70,119,000		36,772,000
Accounts Payable	106,312,000		150,184,000
Affiliated Companies	45,468,000		45,427,000
Short-term Debt:	'		'
Long-term Debt Due Within One Year	34,118,000		34,115,000
Risk Management Liabilities	83,000		85,000
Customer Deposits	45,676,000		45,379,000
Accrued Taxes	44,847,000		23,442,000
Accrued Interest	15,040,000		12,646,000
Other Current Liabilities	80,931,000		58,992,000
TOTAL CURRENT LIABILITIES	442,594,000		407,042,000
Noncurrent Liabilities	'		'
Long-term Debt	1,015,675,000		965,695,000
Deferred Income Taxes	848,101,000		836,556,000
Regulatory Liabilities and Deferred Investment Tax Credits	328,224,000		327,673,000
Employee Benefits and Pension Obligations	9,966,000		10,561,000
Deferred Credits and Other Noncurrent Liabilities	36,634,000		37,066,000
TOTAL NONCURRENT LIABILITIES	2,238,600,000		2,177,551,000
TOTAL LIABILITIES	2,681,194,000		2,584,593,000
Rate Matters	'		'
Commitments and Contingencies	'		'
Equity	'		'
Common Stock	157,230,000		157,230,000
Paid-in Capital	364,037,000		364,037,000
Retained Earnings	423,524,000		415,076,000
Accumulated Other Comprehensive Income (Loss)	5,512,000		5,758,000
TOTAL EQUITY	950,303,000		942,101,000
TOTAL LIABILITIES AND EQUITY	3,631,497,000		3,526,694,000
Southwestern Electric Power Co [Member]	'		'
Current Assets	'		'
Cash and Cash Equivalents	17,995,000		17,241,000
Accounts Receivable:	'		'
Customers	76,416,000		86,263,000
Affiliated Companies	21,341,000		22,389,000
Miscellaneous	24,380,000		27,175,000
Allowance for Uncollectible Accounts	-1,342,000		-1,418,000
Total Accounts Receivable	120,795,000		134,409,000
Fuel	116,294,000		122,026,000
Materials and Supplies	75,492,000		74,862,000
Risk Management Assets	1,907,000		1,179,000
Deferred Income Tax Benefits	170,410,000		177,297,000
Regulatory Asset for Under-Recovered Fuel Costs	32,325,000		17,949,000
Prepayments and Other Current Assets	24,786,000		21,089,000
TOTAL CURRENT ASSETS	560,004,000		566,052,000
Property, Plant and Equipment	'		'
Generation	3,790,809,000		3,764,429,000
Transmission	1,190,356,000		1,165,167,000
Distribution	1,850,573,000		1,843,912,000
Other Property, Plant and Equipment	873,458,000		869,230,000
Construction Work in Progress	309,200,000		281,849,000
Total Property, Plant and Equipment	8,014,396,000		7,924,587,000
Accumulated Depreciation and Amortization	2,424,701,000		2,391,652,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	5,589,695,000		5,532,935,000
Other Noncurrent Assets	'		'
Regulatory Assets	367,406,000		369,905,000
Deferred Charges and Other Noncurrent Assets	133,123,000		92,890,000
TOTAL OTHER NONCURRENT ASSETS	500,529,000		462,795,000
TOTAL ASSETS	6,650,228,000		6,561,782,000
Current Liabilities	'		'
Advances from Affiliates	117,342,000		9,180,000
Accounts Payable	138,177,000		152,653,000
Affiliated Companies	53,742,000		56,923,000
Short-term Debt:	'		'
Long-term Debt Due Within One Year	56,750,000		3,250,000
Customer Deposits	57,065,000		56,375,000
Accrued Taxes	83,946,000		41,508,000
Accrued Interest	18,565,000		43,996,000
Obligations Under Capital Leases	18,220,000		17,899,000
Regulatory Liability for Over-Recovered Fuel Costs	0		7,275,000
Other Current Liabilities	61,448,000		79,622,000
TOTAL CURRENT LIABILITIES	605,255,000		468,681,000
Noncurrent Liabilities	'		'
Long-term Debt	1,985,046,000		2,040,082,000
Deferred Income Taxes	1,277,745,000		1,271,478,000
Regulatory Liabilities and Deferred Investment Tax Credits	477,469,000		472,128,000
Asset Retirement Obligations	88,866,000		87,630,000
Employee Benefits and Pension Obligations	13,914,000		14,602,000
Obligations Under Capital Leases	102,984,000		105,086,000
Deferred Credits and Other Noncurrent Liabilities	46,038,000		46,178,000
TOTAL NONCURRENT LIABILITIES	3,992,062,000		4,037,184,000
TOTAL LIABILITIES	4,597,317,000		4,505,865,000
Rate Matters	'		'
Commitments and Contingencies	'		'
Equity	'		'
Common Stock	135,660,000		135,660,000
Paid-in Capital	674,606,000		674,606,000
Retained Earnings	1,250,477,000		1,253,617,000
Accumulated Other Comprehensive Income (Loss)	-8,176,000		-8,444,000
TOTAL COMMON SHAREHOLDER'S EQUITY	2,052,567,000		2,055,439,000
Noncontrolling Interests	344,000		478,000
TOTAL EQUITY	2,052,911,000		2,055,917,000
TOTAL LIABILITIES AND EQUITY	$6,650,228,000		$6,561,782,000

[1]	Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Current Assets	'	'
Cash and Cash Equivalents	$292,000,000	$118,000,000
Other Temporary Investments	310,000,000	353,000,000
Fuel	490,000,000	701,000,000
Property, Plant and Equipment	'	'
Other Property, Plant and Equipment	5,552,000,000	5,470,000,000
Accumulated Depreciation and Amortization	19,564,000,000	19,288,000,000
Current Liabilities	'	'
Long-term Debt Due Within One Year	1,612,000,000	1,549,000,000
Noncurrent Liabilities	'	'
Long-term Debt	16,475,000,000	16,828,000,000
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	508,397,086	508,113,964
Treasury Stock, Shares	20,336,592	20,336,592
Appalachian Power Co [Member]	'	'
Current Assets	'	'
Cash and Cash Equivalents	4,758,000	2,745,000
Fuel	103,983,000	191,811,000
Property, Plant and Equipment	'	'
Other Property, Plant and Equipment	365,750,000	357,517,000
Accumulated Depreciation and Amortization	3,679,394,000	3,617,990,000
Current Liabilities	'	'
Long-term Debt Due Within One Year	553,399,000	342,360,000
Noncurrent Liabilities	'	'
Long-term Debt	3,555,117,000	3,765,997,000
Equity	'	'
Common Stock, No Par Value	'	'
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	2,288,000	1,317,000
Fuel	49,365,000	53,807,000
Property, Plant and Equipment	'	'
Other Property, Plant and Equipment	1,440,408,000	1,421,361,000
Accumulated Depreciation and Amortization	3,337,401,000	3,299,349,000
Current Liabilities	'	'
Long-term Debt Due Within One Year	287,598,000	294,845,000
Noncurrent Liabilities	'	'
Long-term Debt	1,725,246,000	1,744,171,000
Equity	'	'
Common Stock, No Par Value	'	'
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	99,439,000	107,143,000
Ohio Power Co [Member]	'	'
Current Assets	'	'
Cash and Cash Equivalents	4,780,000	3,004,000
Property, Plant and Equipment	'	'
Other Property, Plant and Equipment	379,780,000	364,573,000
Accumulated Depreciation and Amortization	1,986,318,000	1,973,042,000
Current Liabilities	'	'
Long-term Debt Due Within One Year	235,785,000	438,595,000
Noncurrent Liabilities	'	'
Long-term Debt	2,274,500,000	2,296,580,000
Equity	'	'
Common Stock, No Par Value	'	'
Common Stock, Shares Authorized	40,000,000	40,000,000
Common Stock, Shares Outstanding	27,952,473	27,952,473
Ohio Power Co [Member] \| Ohio Phase-In-Recovery Funding [Member]	'	'
Current Liabilities	'	'
Long-term Debt Due Within One Year	57,137,000	34,936,000
Noncurrent Liabilities	'	'
Long-term Debt	210,266,000	232,466,000
Public Service Co Of Oklahoma [Member]	'	'
Current Assets	'	'
Cash and Cash Equivalents	1,756,000	1,277,000
Fuel	15,054,000	15,191,000
Property, Plant and Equipment	'	'
Other Property, Plant and Equipment	411,700,000	393,026,000
Accumulated Depreciation and Amortization	1,334,507,000	1,323,522,000
Current Liabilities	'	'
Long-term Debt Due Within One Year	34,118,000	34,115,000
Noncurrent Liabilities	'	'
Long-term Debt	1,015,675,000	965,695,000
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	17,995,000	17,241,000
Fuel	116,294,000	122,026,000
Property, Plant and Equipment	'	'
Other Property, Plant and Equipment	873,458,000	869,230,000
Accumulated Depreciation and Amortization	2,424,701,000	2,391,652,000
Current Liabilities	'	'
Long-term Debt Due Within One Year	56,750,000	3,250,000
Noncurrent Liabilities	'	'
Long-term Debt	1,985,046,000	2,040,082,000
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	15,539,000	15,827,000
Fuel	36,143,000	37,518,000
Property, Plant and Equipment	'	'
Other Property, Plant and Equipment	291,571,000	291,556,000
Accumulated Depreciation and Amortization	138,789,000	134,282,000
AEP Subsidiaries [Member]	'	'
Current Assets	'	'
Other Temporary Investments	293,000,000	335,000,000
Current Liabilities	'	'
Long-term Debt Due Within One Year	449,000,000	416,000,000
Noncurrent Liabilities	'	'
Long-term Debt	$2,388,000,000	$2,532,000,000

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Cash Flows (USD $)	3 Months Ended
Condensed Consolidated Statements of Cash Flows (USD $)	Mar. 31, 2014	Mar. 31, 2013
Operating Activities	'	'
Net Income (Loss)	$561,000,000	$364,000,000
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:	'	'
Depreciation and Amortization	491,000,000	420,000,000
Deferred Income Taxes	299,000,000	246,000,000
Carrying Costs Income	-6,000,000	-4,000,000
Allowance for Equity Funds Used During Construction	-22,000,000	-15,000,000
Mark-to-Market of Risk Management Contracts	6,000,000	34,000,000
Amortization of Nuclear Fuel	38,000,000	34,000,000
Property Taxes	-54,000,000	-51,000,000
Fuel Over/Under-Recovery, Net	-137,000,000	-4,000,000
Deferral of Ohio Capacity Costs, Net	-56,000,000	-49,000,000
Change in Other Noncurrent Assets	-25,000,000	36,000,000
Change in Other Noncurrent Liabilities	77,000,000	17,000,000
Changes in Certain Components of Working Capital:	'	'
Accounts Receivable, Net	-83,000,000	-4,000,000
Fuel, Materials and Supplies	209,000,000	-1,000,000
Accounts Payable	33,000,000	-3,000,000
Accrued Taxes, Net	-16,000,000	-69,000,000
Other Current Assets	-51,000,000	-16,000,000
Other Current Liabilities	-131,000,000	-179,000,000
Net Cash Flows from (Used for) Operating Activities	1,133,000,000	756,000,000
Investing Activities	'	'
Construction Expenditures	-907,000,000	-843,000,000
Change in Other Temporary Investments, Net	44,000,000	75,000,000
Purchases of Investment Securities	-165,000,000	-196,000,000
Sales of Investment Securities	148,000,000	168,000,000
Acquisitions of Nuclear Fuel	-49,000,000	-47,000,000
Acquisitions of Assets/Businesses	-43,000,000	-2,000,000
Insurance Proceeds Related to Cook Plant Fire	0	72,000,000
Other Investing Activities	-9,000,000	1,000,000
Net Cash Flows from (Used for) Investing Activities	-981,000,000	-772,000,000
Financing Activities	'	'
Issuance of Common Stock, Net	15,000,000	15,000,000
Issuance of Long-term Debt	76,000,000	671,000,000
Credit Facility Borrowings	0	17,000,000
Change in Short-term Debt, Net	575,000,000	329,000,000
Retirement of Long-term Debt	-370,000,000	-858,000,000
Credit Facility Repayments	0	-20,000,000
Principal Payments for Capital Lease Obligations	-33,000,000	-16,000,000
Dividends Paid on Common Stock	-245,000,000	-230,000,000
Other Financing Activities	4,000,000	8,000,000
Net Cash Flows from (Used for) Financing Activities	22,000,000	-84,000,000
Net Increase (Decrease) in Cash and Cash Equivalents	174,000,000	-100,000,000
Cash and Cash Equivalents at Beginning of Period	118,000,000	279,000,000
Cash and Cash Equivalents at End of Period	292,000,000	179,000,000
Supplementary Information	'	'
Cash Paid for Interest, Net of Capitalized Amounts	234,000,000	253,000,000
Net Cash Paid (Received) for Income Taxes	-6,000,000	-19,000,000
Noncash Acquisitions Under Capital Leases	20,000,000	24,000,000
Construction Expenditures Included in Current Liabilities as of March 31,	387,000,000	300,000,000
Appalachian Power Co [Member]	'	'
Operating Activities	'	'
Net Income (Loss)	101,851,000	70,548,000
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:	'	'
Depreciation and Amortization	104,586,000	87,903,000
Deferred Income Taxes	65,690,000	17,185,000
Carrying Costs Income	1,875,000	-103,000
Allowance for Equity Funds Used During Construction	-1,235,000	-770,000
Mark-to-Market of Risk Management Contracts	1,625,000	9,404,000
Fuel Over/Under-Recovery, Net	-102,051,000	20,135,000
Change in Other Noncurrent Assets	4,959,000	28,314,000
Change in Other Noncurrent Liabilities	7,799,000	5,634,000
Changes in Certain Components of Working Capital:	'	'
Accounts Receivable, Net	41,382,000	7,238,000
Fuel, Materials and Supplies	88,057,000	-8,726,000
Accounts Payable	-4,314,000	-20,597,000
Accrued Taxes, Net	929,000	30,197,000
Other Current Assets	-7,276,000	642,000
Other Current Liabilities	-6,707,000	-10,917,000
Net Cash Flows from (Used for) Operating Activities	297,170,000	236,087,000
Investing Activities	'	'
Construction Expenditures	-112,824,000	-110,552,000
Change in Advances to Affiliates, Net	-153,031,000	-179,000
Other Investing Activities	-8,677,000	-179,000
Net Cash Flows from (Used for) Investing Activities	-274,532,000	-110,910,000
Financing Activities	'	'
Issuance of Long-term Debt	-45,000	-258,000
Change in Advances from Affiliates, Net	0	-77,314,000
Retirement of Long-term Debt	-8,000	-7,000
Principal Payments for Capital Lease Obligations	-1,559,000	-1,238,000
Dividends Paid on Common Stock	-20,000,000	-50,000,000
Other Financing Activities	987,000	1,320,000
Net Cash Flows from (Used for) Financing Activities	-20,625,000	-127,497,000
Net Increase (Decrease) in Cash and Cash Equivalents	2,013,000	-2,320,000
Cash and Cash Equivalents at Beginning of Period	2,745,000	3,576,000
Cash and Cash Equivalents at End of Period	4,758,000	1,256,000
Supplementary Information	'	'
Cash Paid for Interest, Net of Capitalized Amounts	39,431,000	31,018,000
Net Cash Paid (Received) for Income Taxes	0	231,000
Noncash Acquisitions Under Capital Leases	2,657,000	1,548,000
Construction Expenditures Included in Current Liabilities as of March 31,	38,972,000	35,733,000
Indiana Michigan Power Co [Member]	'	'
Operating Activities	'	'
Net Income (Loss)	87,089,000	43,457,000
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:	'	'
Depreciation and Amortization	50,031,000	40,902,000
Deferred Income Taxes	21,017,000	26,791,000
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expense, Net	14,821,000	-5,840,000
Allowance for Equity Funds Used During Construction	-3,964,000	-5,646,000
Mark-to-Market of Risk Management Contracts	426,000	9,238,000
Amortization of Nuclear Fuel	38,049,000	34,000,000
Fuel Over/Under-Recovery, Net	11,683,000	417,000
Change in Other Noncurrent Assets	-16,211,000	-9,217,000
Change in Other Noncurrent Liabilities	11,505,000	8,577,000
Changes in Certain Components of Working Capital:	'	'
Accounts Receivable, Net	24,411,000	22,531,000
Fuel, Materials and Supplies	7,340,000	-6,868,000
Accounts Payable	-20,902,000	-31,801,000
Accrued Taxes, Net	29,583,000	14,198,000
Other Current Assets	5,933,000	8,487,000
Other Current Liabilities	-18,862,000	-13,443,000
Net Cash Flows from (Used for) Operating Activities	241,949,000	135,783,000
Investing Activities	'	'
Construction Expenditures	-117,807,000	-153,262,000
Change in Advances to Affiliates, Net	-3,299,000	-205,008,000
Purchases of Investment Securities	-164,511,000	-184,299,000
Sales of Investment Securities	147,700,000	167,670,000
Acquisitions of Nuclear Fuel	-49,420,000	-46,739,000
Insurance Proceeds Related to Cook Plant Fire	0	72,000,000
Other Investing Activities	8,860,000	3,077,000
Net Cash Flows from (Used for) Investing Activities	-178,477,000	-346,561,000
Financing Activities	'	'
Issuance of Long-term Debt	0	247,771,000
Retirement of Long-term Debt	-26,337,000	-24,864,000
Principal Payments for Capital Lease Obligations	-11,569,000	-1,265,000
Dividends Paid on Common Stock	-25,000,000	-12,500,000
Other Financing Activities	405,000	646,000
Net Cash Flows from (Used for) Financing Activities	-62,501,000	209,788,000
Net Increase (Decrease) in Cash and Cash Equivalents	971,000	-990,000
Cash and Cash Equivalents at Beginning of Period	1,317,000	1,562,000
Cash and Cash Equivalents at End of Period	2,288,000	572,000
Supplementary Information	'	'
Cash Paid for Interest, Net of Capitalized Amounts	34,592,000	30,116,000
Net Cash Paid (Received) for Income Taxes	0	-8,007,000
Noncash Acquisitions Under Capital Leases	2,406,000	1,355,000
Construction Expenditures Included in Current Liabilities as of March 31,	56,668,000	42,430,000
Acquisition of Nuclear Fuel Included in Current Liabilities as of March 31,	116,000	1,485,000
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	854,000	0
Ohio Power Co [Member]	'	'
Operating Activities	'	'
Net Income (Loss)	60,774,000	129,774,000
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:	'	'
Depreciation and Amortization	58,699,000	92,324,000
Amortization of Generation Deferrals	31,186,000	0
Deferred Income Taxes	24,917,000	55,328,000
Carrying Costs Income	-7,114,000	-3,263,000
Allowance for Equity Funds Used During Construction	-1,726,000	-1,304,000
Mark-to-Market of Risk Management Contracts	-1,060,000	12,901,000
Property Taxes	48,743,000	55,246,000
Fuel Over/Under-Recovery, Net	12,265,000	9,191,000
Deferral of Ohio Capacity Costs, Net	-56,167,000	-49,056,000
Change in Other Noncurrent Assets	-21,285,000	14,092,000
Change in Other Noncurrent Liabilities	29,277,000	1,730,000
Changes in Certain Components of Working Capital:	'	'
Accounts Receivable, Net	-34,984,000	58,235,000
Fuel, Materials and Supplies	-1,600,000	-1,388,000
Accounts Payable	-30,911,000	-42,749,000
Accrued Taxes, Net	-98,147,000	-91,308,000
Other Current Assets	-1,415,000	-705,000
Other Current Liabilities	-13,633,000	-21,374,000
Net Cash Flows from (Used for) Operating Activities	-2,181,000	217,674,000
Investing Activities	'	'
Construction Expenditures	-100,220,000	-131,590,000
Change in Restricted Cash for Securitized Funding	-12,668,000	0
Change in Advances to Affiliates, Net	339,070,000	106,080,000
Other Investing Activities	1,162,000	9,760,000
Net Cash Flows from (Used for) Investing Activities	227,344,000	-15,750,000
Financing Activities	'	'
Issuance of Long-term Debt - Affiliated	0	200,000,000
Change in Advances from Affiliates, Net	27,108,000	172,211,000
Retirement of Long-term Debt	-225,029,000	-500,000,000
Principal Payments for Capital Lease Obligations	-1,396,000	-2,508,000
Dividends Paid on Common Stock	-25,000,000	-75,000,000
Other Financing Activities	930,000	760,000
Net Cash Flows from (Used for) Financing Activities	-223,387,000	-204,537,000
Net Increase (Decrease) in Cash and Cash Equivalents	1,776,000	-2,613,000
Cash and Cash Equivalents at Beginning of Period	3,004,000	3,640,000
Cash and Cash Equivalents at End of Period	4,780,000	1,027,000
Supplementary Information	'	'
Cash Paid for Interest, Net of Capitalized Amounts	23,425,000	50,327,000
Net Cash Paid (Received) for Income Taxes	0	-2,390,000
Noncash Acquisitions Under Capital Leases	3,324,000	1,811,000
Government Grants Included in Accounts Receivable as of March 31,	0	1,147,000
Construction Expenditures Included in Current Liabilities as of March 31,	46,910,000	69,152,000
Public Service Co Of Oklahoma [Member]	'	'
Operating Activities	'	'
Net Income (Loss)	8,448,000	13,693,000
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:	'	'
Depreciation and Amortization	23,982,000	24,180,000
Deferred Income Taxes	19,178,000	20,242,000
Allowance for Equity Funds Used During Construction	-1,431,000	-980,000
Mark-to-Market of Risk Management Contracts	-267,000	-3,013,000
Property Taxes	-31,260,000	-28,730,000
Fuel Over/Under-Recovery, Net	-23,394,000	-17,812,000
Change In Regulatory Assets	-8,468,000	4,165,000
Change in Other Noncurrent Assets	-1,045,000	-3,780,000
Change in Other Noncurrent Liabilities	-2,204,000	4,620,000
Changes in Certain Components of Working Capital:	'	'
Accounts Receivable, Net	14,193,000	1,665,000
Fuel, Materials and Supplies	149,000	1,344,000
Accounts Payable	-16,891,000	-5,827,000
Accrued Taxes, Net	7,362,000	6,106,000
Other Current Assets	-395,000	1,181,000
Other Current Liabilities	22,401,000	10,663,000
Net Cash Flows from (Used for) Operating Activities	10,358,000	27,717,000
Investing Activities	'	'
Construction Expenditures	-93,500,000	-54,298,000
Change in Advances to Affiliates, Net	0	10,558,000
Other Investing Activities	776,000	5,196,000
Net Cash Flows from (Used for) Investing Activities	-92,724,000	-38,544,000
Financing Activities	'	'
Issuance of Long-term Debt	49,975,000	0
Change in Advances from Affiliates, Net	33,347,000	24,004,000
Retirement of Long-term Debt	-102,000	-99,000
Principal Payments for Capital Lease Obligations	-941,000	-754,000
Dividends Paid on Common Stock	0	-13,750,000
Other Financing Activities	566,000	533,000
Net Cash Flows from (Used for) Financing Activities	82,845,000	9,934,000
Net Increase (Decrease) in Cash and Cash Equivalents	479,000	-893,000
Cash and Cash Equivalents at Beginning of Period	1,277,000	1,367,000
Cash and Cash Equivalents at End of Period	1,756,000	474,000
Supplementary Information	'	'
Cash Paid for Interest, Net of Capitalized Amounts	10,487,000	10,519,000
Net Cash Paid (Received) for Income Taxes	67,000	284,000
Noncash Acquisitions Under Capital Leases	904,000	1,015,000
Construction Expenditures Included in Current Liabilities as of March 31,	34,199,000	19,868,000
Southwestern Electric Power Co [Member]	'	'
Operating Activities	'	'
Net Income (Loss)	22,962,000	11,548,000
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:	'	'
Depreciation and Amortization	45,661,000	44,882,000
Deferred Income Taxes	11,351,000	25,583,000
Allowance for Equity Funds Used During Construction	-2,081,000	-1,024,000
Mark-to-Market of Risk Management Contracts	-825,000	-293,000
Property Taxes	-37,511,000	-36,161,000
Fuel Over/Under-Recovery, Net	-21,651,000	-7,496,000
Change in Other Noncurrent Assets	3,963,000	-1,245,000
Change in Other Noncurrent Liabilities	2,914,000	4,953,000
Changes in Certain Components of Working Capital:	'	'
Accounts Receivable, Net	13,614,000	11,654,000
Fuel, Materials and Supplies	5,102,000	3,303,000
Accounts Payable	-9,410,000	-12,658,000
Customer Deposits	690,000	-14,202,000
Accrued Taxes, Net	42,596,000	27,994,000
Accrued Interest	-25,431,000	-25,447,000
Other Current Assets	-4,663,000	-638,000
Other Current Liabilities	-18,813,000	-13,551,000
Net Cash Flows from (Used for) Operating Activities	28,468,000	17,202,000
Investing Activities	'	'
Construction Expenditures	-105,165,000	-97,786,000
Change in Advances to Affiliates, Net	0	126,944,000
Other Investing Activities	1,046,000	-1,108,000
Net Cash Flows from (Used for) Investing Activities	-104,119,000	28,050,000
Financing Activities	'	'
Credit Facility Borrowings	0	17,091,000
Change in Advances from Affiliates, Net	108,162,000	0
Retirement of Long-term Debt	-1,625,000	-1,625,000
Credit Facility Repayments	0	-19,694,000
Principal Payments for Capital Lease Obligations	-4,470,000	-4,225,000
Dividends Paid on Common Stock	-25,000,000	-31,250,000
Dividends Paid on Common Stock	-1,236,000	-964,000
Other Financing Activities	574,000	522,000
Net Cash Flows from (Used for) Financing Activities	76,405,000	-40,145,000
Net Increase (Decrease) in Cash and Cash Equivalents	754,000	5,107,000
Cash and Cash Equivalents at Beginning of Period	17,241,000	2,036,000
Cash and Cash Equivalents at End of Period	17,995,000	7,143,000
Supplementary Information	'	'
Cash Paid for Interest, Net of Capitalized Amounts	55,123,000	55,626,000
Net Cash Paid (Received) for Income Taxes	734,000	-8,387,000
Noncash Acquisitions Under Capital Leases	2,824,000	2,454,000
Construction Expenditures Included in Current Liabilities as of March 31,	$53,628,000	$40,990,000

Significant_Accounting_Matters

Significant Accounting Matters

3 Months Ended

Mar. 31, 2014

Significant Accounting Matters

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2013 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2014.

Revenue Recognition

Electricity Supply and Delivery Activities – Transactions with PJM

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

APCo, I&M and KPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.

AEP's nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales.

Earnings Per Share (EPS)

Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.

The following table presents our basic and diluted EPS calculations included on our condensed statements of income:

Three Months Ended March 31,

2014

2013

(in millions, except per share data)

$/share

Earnings Attributable to AEP Common Shareholders

560

363

Weighted Average Number of Basic Shares Outstanding

487.9

1.15

485.8

0.75

Weighted Average Dilutive Effect of:

Restricted Stock Units

0.4

0.5

Weighted Average Number of Diluted Shares Outstanding

488.3

1.15

486.3

0.75

There were no antidilutive shares outstanding as of March 31, 2014 and 2013.

Appalachian Power Co [Member]

Significant Accounting Matters

1. SIGNIFICANT ACCOUNTING MATTERS

General

The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014.

Revenue Recognition

Electricity Supply and Delivery Activities – Transactions with PJM

Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenues on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.

Indiana Michigan Power Co [Member]

Significant Accounting Matters

1. SIGNIFICANT ACCOUNTING MATTERS

General

Revenue Recognition

Electricity Supply and Delivery Activities – Transactions with PJM

Ohio Power Co [Member]

Significant Accounting Matters

1. SIGNIFICANT ACCOUNTING MATTERS

General

Public Service Co Of Oklahoma [Member]

Significant Accounting Matters

1. SIGNIFICANT ACCOUNTING MATTERS

General

Southwestern Electric Power Co [Member]

Significant Accounting Matters

1. SIGNIFICANT ACCOUNTING MATTERS

General

New_Accounting_Pronouncements

New Accounting Pronouncements	3 Months Ended
New Accounting Pronouncements	Mar. 31, 2014
New Accounting Pronouncements	'
	2. NEW ACCOUNTING PRONOUNCEMENT

	Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following summary of a final pronouncement will impact our financial statements.

	ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

	In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

	The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of our financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. We plan to adopt ASU 2014-08 effective January 1, 2015.

Appalachian Power Co [Member]	'
New Accounting Pronouncements	'
	2. NEW ACCOUNTING PRONOUNCEMENT

	Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements.

	ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

	In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

	The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015.

Indiana Michigan Power Co [Member]	'
New Accounting Pronouncements	'
	2. NEW ACCOUNTING PRONOUNCEMENT

	Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements.

	ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

	In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

	The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015.

Ohio Power Co [Member]	'
New Accounting Pronouncements	'
	2. NEW ACCOUNTING PRONOUNCEMENT

	Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements.

	ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

	In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

	The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015.

Public Service Co Of Oklahoma [Member]	'
New Accounting Pronouncements	'
	2. NEW ACCOUNTING PRONOUNCEMENT

	Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements.

	ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

	In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

	The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015.

Southwestern Electric Power Co [Member]	'
New Accounting Pronouncements	'
	2. NEW ACCOUNTING PRONOUNCEMENT

	Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries' business. The following summary of a final pronouncement will impact the financial statements.

	ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08)

	In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity's operations and financial results when the component meets the criteria to be classified as held for sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. Early adoption is permitted for disposals that have not been reported in financial statements previously issued or available for issuance.

	The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management plans to adopt ASU 2014-08 effective January 1, 2015.

Comprehensive_Income

Comprehensive Income	3 Months Ended
Comprehensive Income	Mar. 31, 2014
Comprehensive Income	'
	3. COMPREHENSIVE INCOME

	Presentation of Comprehensive Income

	The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 2013. All amounts in the following tables are presented net of related income taxes.
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 2014

				Cash Flow Hedges
							Interest Rate and			Securities			Pension
				Commodity			Foreign Currency			Available for Sale			and OPEB			Total
				(in millions)
	Balance in AOCI as of December 31, 2013			$	-		$	-23		$	7		$	-99		$	-115
	Change in Fair Value Recognized in AOCI				-14			-			-			-			-14
	Amounts Reclassified from AOCI				18			1			-			1			20
	Net Current Period Other
			Comprehensive Income		4			1			-			1			6
	Balance in AOCI as of March 31, 2014			$	4		$	-22		$	7		$	-98		$	-109

	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 2013

				Cash Flow Hedges
							Interest Rate and			Securities			Pension
				Commodity			Foreign Currency			Available for Sale			and OPEB			Total
				(in millions)
	Balance in AOCI as of December 31, 2012			$	-8		$	-30		$	4		$	-303		$	-337
	Change in Fair Value Recognized in AOCI				18			3			1			-			22
	Amounts Reclassified from AOCI				2			1			-			6			9
	Net Current Period Other
			Comprehensive Income		20			4			1			6			31
	Balance in AOCI as of March 31, 2013			$	12		$	-26		$	5		$	-297		$	-306
	Reclassifications from Accumulated Other Comprehensive Income

	The following table provides details of reclassifications from AOCI for the three months ended March 31, 2014 and 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details.
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in millions)
		Commodity:
				Vertically Integrated Utilities Revenues		$	-		$	-
				Generation & Marketing Revenues			-			-3
				Purchased Electricity for Resale			31			6
				Property, Plant and Equipment			-			-
				Regulatory Assets/(Liabilities), Net (a)			-3			-
		Subtotal - Commodity					28			3

		Interest Rate and Foreign Currency:
				Interest Expense			2			2
		Subtotal - Interest Rate and Foreign Currency					2			2

		Reclassifications from AOCI, before Income Tax (Expense) Credit					30			5
		Income Tax (Expense) Credit					11			2
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					19			3

		Gains and Losses on Securities Available for Sale
		Interest Income					-			-
		Interest Expense					-			-
	Reclassifications from AOCI, before Income Tax (Expense) Credit					-			-
	Income Tax (Expense) Credit					-			-
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-			-

	Pension and OPEB
	Amortization of Prior Service Cost (Credit)					-5			-5
	Amortization of Actuarial (Gains)/Losses					7			14
	Reclassifications from AOCI, before Income Tax (Expense) Credit					2			9
	Income Tax (Expense) Credit					1			3
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit					1			6

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	20		$	9
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Appalachian Power Co [Member]	'
Comprehensive Income	'
	3. COMPREHENSIVE INCOME

	Presentation of Comprehensive Income

	The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 2013. All amounts in the following tables are presented net of related income taxes.
	APCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2013			$	94		$	3,090		$	-233		$	2,951
		Change in Fair Value Recognized in AOCI				1,583			-			-			1,583
		Amounts Reclassified from AOCI				-1,590			253			-333			-1,670
		Net Current Period Other
				Comprehensive Income		-7			253			-333			-87
		Balance in AOCI as of March 31, 2014			$	87		$	3,343		$	-566		$	2,864

	APCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	-644		$	2,077		$	-31,331		$	-29,898
		Change in Fair Value Recognized in AOCI				794			-1			-			793
		Amounts Reclassified from AOCI				211			254			358			823
		Net Current Period Other
				Comprehensive Income		1,005			253			358			1,616
		Balance in AOCI as of March 31, 2013			$	361		$	2,330		$	-30,973		$	-28,282
	Reclassifications from Accumulated Other Comprehensive Income

	The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details.
	APCo
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Electric Generation, Transmission and Distribution Revenues		$	-		$	20
				Purchased Electricity for Resale			-462			57
				Other Operation Expense			-10			-11
				Maintenance Expense			-20			-16
				Property, Plant and Equipment			-17			-14
				Regulatory Assets/(Liabilities), Net (a)			-1,937			289
		Subtotal - Commodity					-2,446			325

		Interest Rate and Foreign Currency:
				Interest Expense			390			390
		Subtotal - Interest Rate and Foreign Currency					390			390

		Reclassifications from AOCI, before Income Tax (Expense) Credit					-2,056			715
		Income Tax (Expense) Credit					-719			250
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-1,337			465

	Pension and OPEB
	Amortization of Prior Service Cost (Credit)					-1,282			-1,282
	Amortization of Actuarial (Gains)/Losses					770			1,833
	Reclassifications from AOCI, before Income Tax (Expense) Credit					-512			551
	Income Tax (Expense) Credit					-179			193
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-333			358

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	-1,670		$	823
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Indiana Michigan Power Co [Member]	'
Comprehensive Income	'
	3. COMPREHENSIVE INCOME

	Presentation of Comprehensive Income

	The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 2013. All amounts in the following tables are presented net of related income taxes.
	I&M
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2013			$	46		$	-15,976		$	421		$	-15,509
		Change in Fair Value Recognized in AOCI				1,062			-			-			1,062
		Amounts Reclassified from AOCI				-1,047			410			43			-594
		Net Current Period Other
				Comprehensive Income		15			410			43			468
		Balance in AOCI as of March 31, 2014			$	61		$	-15,566		$	464		$	-15,041

	I&M
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	-446		$	-19,647		$	-8,790		$	-28,883
		Change in Fair Value Recognized in AOCI				532			2,249			-			2,781
		Amounts Reclassified from AOCI				150			192			176			518
		Net Current Period Other
				Comprehensive Income		682			2,441			176			3,299
		Balance in AOCI as of March 31, 2013			$	236		$	-17,206		$	-8,614		$	-25,584
	Reclassifications from Accumulated Other Comprehensive Income

	The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details.
	I&M
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Electric Generation, Transmission and Distribution Revenues		$	-		$	52
				Purchased Electricity for Resale			-717			149
				Other Operation Expense			-7			-7
				Maintenance Expense			-7			-7
				Property, Plant and Equipment			-10			-7
				Regulatory Assets/(Liabilities), Net (a)			-870			50
		Subtotal - Commodity					-1,611			230

		Interest Rate and Foreign Currency:
				Interest Expense			631			296
		Subtotal - Interest Rate and Foreign Currency					631			296

		Reclassifications from AOCI, before Income Tax (Expense) Credit					-980			526
		Income Tax (Expense) Credit					-343			184
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-637			342

	Pension and OPEB
	Amortization of Prior Service Cost (Credit)					-199			-199
	Amortization of Actuarial (Gains)/Losses					265			469
	Reclassifications from AOCI, before Income Tax (Expense) Credit					66			270
	Income Tax (Expense) Credit					23			94
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit					43			176

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	-594		$	518
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Ohio Power Co [Member]	'
Comprehensive Income	'
	3. COMPREHENSIVE INCOME

	Presentation of Comprehensive Income

	The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 2013. All amounts in the following tables are presented net of related income taxes.
	OPCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2013			$	105		$	6,974		$	-		$	7,079
		Change in Fair Value Recognized in AOCI				-			-			-			-
		Amounts Reclassified from AOCI				-105			-343			-			-448
		Net Current Period Other
				Comprehensive Income		-105			-343			-			-448
		Balance in AOCI as of March 31, 2014			$	-		$	6,631		$	-		$	6,631

	OPCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	-912		$	8,095		$	-172,908		$	-165,725
		Change in Fair Value Recognized in AOCI				1,102			-			-			1,102
		Amounts Reclassified from AOCI				304			-340			3,269			3,233
		Net Current Period Other
				Comprehensive Income		1,406			-340			3,269			4,335
		Balance in AOCI as of March 31, 2013			$	494		$	7,755		$	-169,639		$	-161,390
	Reclassifications from Accumulated Other Comprehensive Income

	The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details.
	OPCo
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Electric Generation, Transmission and Distribution Revenues		$	-		$	134
				Purchased Electricity for Resale			-			382
				Other Operation Expense			-11			-18
				Maintenance Expense			-11			-12
				Property, Plant and Equipment			-18			-19
				Regulatory Assets/(Liabilities), Net (a)			-122			-
		Subtotal - Commodity					-162			467

		Interest Rate and Foreign Currency:
				Depreciation and Amortization Expense			-3			2
				Interest Expense			-524			-524
		Subtotal - Interest Rate and Foreign Currency					-527			-522

		Reclassifications from AOCI, before Income Tax (Expense) Credit					-689			-55
		Income Tax (Expense) Credit					-241			-19
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-448			-36

	Pension and OPEB
	Amortization of Prior Service Cost (Credit)					-			-1,468
	Amortization of Actuarial (Gains)/Losses					-			6,497
	Reclassifications from AOCI, before Income Tax (Expense) Credit					-			5,029
	Income Tax (Expense) Credit					-			1,760
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-			3,269

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	-448		$	3,233
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Public Service Co Of Oklahoma [Member]	'
Comprehensive Income	'
	3. COMPREHENSIVE INCOME

	Presentation of Comprehensive Income

	The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 2013. All amounts in the following tables are presented net of related income taxes.
	PSO
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and
					Commodity			Foreign Currency			Total

					(in thousands)
		Balance in AOCI as of December 31, 2013			$	57		$	5,701		$	5,758
		Change in Fair Value Recognized in AOCI				-			-			-
		Amounts Reclassified from AOCI				-57			-189			-246
		Net Current Period Other
				Comprehensive Income		-57			-189			-246
		Balance in AOCI as of March 31, 2014			$	-		$	5,512		$	5,512

	PSO
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and
					Commodity			Foreign Currency			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	21		$	6,460		$	6,481
		Change in Fair Value Recognized in AOCI				36			-			36
		Amounts Reclassified from AOCI				-13			-190			-203
		Net Current Period Other
				Comprehensive Income		23			-190			-167
		Balance in AOCI as of March 31, 2013			$	44		$	6,270		$	6,314
	Reclassifications from Accumulated Other Comprehensive Income

	The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details.
	PSO
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Other Operation Expense		$	-8		$	-9
				Maintenance Expense			-9			-4
				Property, Plant and Equipment			-13			-7
				Regulatory Assets/(Liabilities), Net (a)			-58			-
		Subtotal - Commodity					-88			-20

		Interest Rate and Foreign Currency:
				Interest Expense			-292			-292
		Subtotal - Interest Rate and Foreign Currency					-292			-292

		Reclassifications from AOCI, before Income Tax (Expense) Credit					-380			-312
		Income Tax (Expense) Credit					-134			-109
		Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	-246		$	-203
	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Southwestern Electric Power Co [Member]	'
Comprehensive Income	'
	3. COMPREHENSIVE INCOME

	Presentation of Comprehensive Income

	The following tables provide the components of changes in AOCI for the three months ended March 31, 2014 and 2013. All amounts in the following tables are presented net of related income taxes.
	SWEPCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2013			$	66		$	-13,304		$	4,794		$	-8,444
		Change in Fair Value Recognized in AOCI				-			-			-			-
		Amounts Reclassified from AOCI				-66			568			-234			268
		Net Current Period Other
				Comprehensive Income		-66			568			-234			268
		Balance in AOCI as of March 31, 2014			$	-		$	-12,736		$	4,560		$	-8,176

	SWEPCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	22		$	-15,571		$	-2,311		$	-17,860
		Change in Fair Value Recognized in AOCI				44			-			-			44
		Amounts Reclassified from AOCI				-15			567			-63			489
		Net Current Period Other
				Comprehensive Income		29			567			-63			533
		Balance in AOCI as of March 31, 2013			$	51		$	-15,004		$	-2,374		$	-17,327
	Reclassifications from Accumulated Other Comprehensive Income

	The following tables provide details of reclassifications from AOCI for the three months ended March 31, 2014 and 2013. The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details.
	SWEPCo
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Other Operation Expense		$	-13		$	-10
				Maintenance Expense			-10			-6
				Property, Plant and Equipment			-11			-7
				Regulatory Assets/(Liabilities), Net (a)			-67			-
		Subtotal - Commodity					-101			-23

		Interest Rate and Foreign Currency:
				Interest Expense			872			872
		Subtotal - Interest Rate and Foreign Currency					872			872

		Reclassifications from AOCI, before Income Tax (Expense) Credit					771			849
		Income Tax (Expense) Credit					269			297
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					502			552

		Pension and OPEB
	Amortization of Prior Service Cost (Credit)					-478			-445
	Amortization of Actuarial (Gains)/Losses					118			348
	Reclassifications from AOCI, before Income Tax (Expense) Credit					-360			-97
	Income Tax (Expense) Credit					-126			-34
	Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-234			-63

	Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	268		$	489
(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

Rate_Matters

Rate Matters	3 Months Ended
	Mar. 31, 2014
Rate Matters	'
	4. RATE MATTERS

	As discussed in the 2013 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2013 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2014 and updates the 2013 Annual Report.
	Regulatory Assets Not Yet Being Recovered
						March 31,			December 31,
						2014			2013
		Noncurrent Regulatory Assets				(in millions)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Earning a Return
			Storm Related Costs			$	21		$	22
			Ohio Economic Development Rider				-			14
			Other Regulatory Assets Not Yet Being Recovered				-			4
		Regulatory Assets Currently Not Earning a Return
			Storm Related Costs				104			161
			Indiana Under-Recovered Capacity Costs				28			22
			IGCC Pre-Construction Costs				21			-
			Expanded Net Energy Charge - Coal Inventory				19			21
			Mountaineer Carbon Capture and Storage Product Validation Facility				13			13
			Ormet Special Rate Recovery Mechanism				10			36
			Other Regulatory Assets Not Yet Being Recovered				34			37
		Total Regulatory Assets Not Yet Being Recovered				$	250		$	330
	If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
	OPCo Rate Matters

	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. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. 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. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

	In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers' Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO's refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo's net deferred fuel costs up to the total balance. As of March 31, 2014, OPCo's net deferred fuel balance was $426 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO's decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision.

	In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo's net deferred fuel balance up to the total balance. These intervenors' appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of March 31, 2014, could reduce carrying costs by $30 million including $16 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

	Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

	June 2012 – May 2015 ESP Including Capacity Charge

	In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013.

	In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price, which includes reserve margins, is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.
	As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of March 31, 2014, OPCo's incurred deferred capacity costs balance of $348 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

	In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO's ESP order, including the RSR.

	In November 2013, the PUCO issued an order approving OPCo's CBP with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 – 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo's request to implement riders related to the unbundling of the FAC.

	Proposed June 2015 – May 2018 ESP

	In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider, effective June 2015 through May 2018. This filing is consistent with the PUCO's objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. Additionally, the application identifies OPCo's intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the second quarter of 2014. A hearing at the PUCO in the ESP case is scheduled for June 2014.

	If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition.

	Significantly Excessive Earnings Test (SEET) Filings

	In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo's gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In November 2013, OPCo filed its 2011 SEET filing with the PUCO. OPCo was required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo.

	In November 2013, OPCo filed its 2012 SEET filing with the PUCO. In April 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2012 for OPCo. A hearing at the PUCO related to the 2012 SEET filing is scheduled for April 2014. Management does not believe that there were significantly excessive earnings in 2013 for OPCo.
	Corporate Separation

	In October 2012, the PUCO issued an order which approved the corporate separation of OPCo's generation assets including the transfer of OPCo's generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo's generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.
	Storm Damage Recovery Rider (SDRR)

In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses over twelve months starting with the effective date as approved by the PUCO. In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC. The stipulation agreement recommended approval to recover $55 million related to 2012 storm costs over a 12-month period which included a $6 million reduction in the amount of 2012 storm expenses to be recovered. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In April 2014, the PUCO approved the settlement agreement. Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014.

2009 Fuel Adjustment Clause Audit

In January 2012, the PUCO issued an order in OPCo's 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo's under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant's review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges. If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.
2010 and 2011 Fuel Adjustment Clause Audits

The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO were held in November 2013. If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. See the 2009 – 2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding.
2012 – 2013 Fuel Adjustment Clause Audits

In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. If the PUCO orders a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.
Ormet

Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider (EDR), except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet's October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the EDR. In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommends approval of OPCo's right to fully recover approximately $49 million of foregone revenues through the EDR which, as of March 31, 2014, is recorded in regulatory assets on the balance sheet. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In March 2014, the PUCO issued an order in OPCo's EDR filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement is scheduled for May 2014.

In addition, in the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement.

To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.
Ohio IGCC Plant

In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of March 31, 2014, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding could have on future net income and cash flows. However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.
SWEPCo Rate Matters

2012 Texas Base Rate Case

In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant's Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo's recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of March 31, 2014, the net book value of Welsh Plant, Unit 2 was $86 million, before cost of removal, including materials and supplies inventory and CWIP.

Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant's Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase is approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling. This order became final and appealable in April 2014.

If any part of the PUCT order is overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs of Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.
2013 Texas Transmission Cost Recovery Factor Filing

In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million. The TCRF is designed to recover increases from the amounts included in SWEPCo's Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo's application included Turk Plant transmission-related costs. In March 2014, the Administrative Law Judge (ALJ) dismissed this case without prejudice. The ALJ concluded that SWEPCo's application was premature as the PUCT had not completed its ruling on the motions for rehearing of the order in the SWEPCo Texas Base Rate Case in which the baseline values to be used in the TCRF calculation would be established.

2012 Louisiana Formula Rate Filing

In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.
2014 Louisiana Formula Rate Filing

In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase to be effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers. These increases are subject to LPSC staff review. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

APCo and WPCo Rate Matters
Plant Transfer

In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In April 2014, APCo and WPCo also filed a request with the FERC for approval to transfer AGR's one-half interest in the Mitchell Plant to WPCo. Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR.

APCo IGCC Plant

As of March 31, 2014, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction. In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
2013 Virginia Transmission Rate Adjustment Clause (transmission RAC)

In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually to be effective May 2014. In March 2014, the Virginia SCC issued an order approving a stipulation agreement between APCo and the Virginia SCC staff increasing the transmission RAC revenues by $49 million annually, subject to true-up, effective May 2014. Pursuant to the order, the Virginia SCC staff will audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC proceeding in 2015.

2014 Virginia Biennial Base Rate Case

In March 2014, APCo filed a generation and distribution base rate biennial review with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. A hearing at the Virginia SCC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

PSO Rate Matters

2014 Oklahoma Base Rate Case

In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

In April 2014, OCC Staff and intervenors filed testimony with recommendations that included adjustments to annual base rates ranging from an increase of $16 million to a reduction of $22 million, primarily based upon the determination of depreciation rates and a return on common equity between 9.18% and 9.5%. Additionally, the recommendations did not support the advanced metering rider or the expansion of the transmission rider. A hearing at the OCC is scheduled for June 2014. If the OCC were to disallow any portion of this base rate request, it could reduce future net income and cash flows and impact financial condition.
I&M Rate Matters

2011 Indiana Base Rate Case

In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2% and adjusted the authorized annual increase in base rates to $92 million in March 2013. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals. In March 2014, the Indiana Court of Appeals upheld the February 2013 IURC order. In April 2014, the OUCC filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base. If any part of the IURC order is overturned by the Indiana Supreme Court, it could reduce future net income and cash flows.
Cook Plant Life Cycle Management Project (LCM Project)

In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of March 31, 2014, I&M has incurred costs of $405 million related to the LCM Project, including AFUDC.

In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.
Tanners Creek Plant, Units 1 - 4

In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant's retirement related costs in its next Indiana and Michigan base rate cases.

In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates are expected to result in a decrease in I&M's Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case. A hearing at the MPSC is scheduled for September 2014.

As of March 31, 2014, the net book value of the Tanners Creek Plant was $334 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.
KPCo Rate Matters
Plant Transfer

In October 2012, the AEP East Companies submitted several filings with the FERC. In December 2012, KPCo filed a request with the KPSC for approval to transfer at net book value to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. KPCo also requested that costs related to the Big Sandy Plant, Unit 2 FGD project be established as a regulatory asset. As of March 31, 2014, the net book value of Big Sandy Plant, Unit 2 was $247 million, before cost of removal, including materials and supplies inventory and CWIP.

In October 2013, the KPSC issued an order approving a modified settlement agreement between KPCo, Kentucky Industrial Utility Customers, Inc. and the Sierra Club. The modified settlement approved the transfer of a one-half interest in the Mitchell Plant to KPCo at net book value on December 31, 2013 with the limitation that the net book value of the Mitchell Plant transfer not exceed the amount to be determined by a WVPSC order. The WVPSC order was subsequently issued in December 2013, but the WVPSC deferred a decision on the transfer of the one-half interest in the Mitchell Plant to APCo. The settlement also included the implementation of an Asset Transfer Rider to collect $44 million annually effective January 2014, subject to true-up, and allowed KPCo to retain any off-system sales margins above the $15.3 million annual level in base rates. Additionally, the settlement allows for KPCo to file a Certificate of Public Convenience and Necessity to convert Big Sandy Plant, Unit 1 to natural gas, provided the cost is approximately $60 million, and addressed potential greenhouse gas initiatives on the Mitchell Plant. The settlement also approved recovery, including a return, of coal-related retirement costs related to Big Sandy Plant over 25 years when base rates are set in the next base rate case (no earlier than June 2015), but rejected KPCo's request to defer FGD project costs for Big Sandy Plant, Unit 2. As a result of this order, in 2013, KPCo recorded a pretax regulatory disallowance of $33 million in Asset Impairments and Other Related Charges on the statement of income. In December 2013, the Attorney General filed an appeal with the Franklin County Circuit Court. In December 2013, KPCo filed motions with the Franklin County Circuit Court to dismiss the appeal. A hearing on the motions to dismiss was held in January 2014. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. If any part of the KPSC order is overturned, it could reduce future net income and cash flows and impact financial condition.
Appalachian Power Co [Member]	'
Rate Matters	'
	Plant Transfer

	In March 2014, APCo and WPCo filed a request with the WVPSC for approval to transfer at net book value to WPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity presently owned by AGR. In April 2014, APCo and WPCo filed testimony that supported their request and proposed a base rate surcharge of $113 million, to be offset by an equal reduction in the ENEC revenues, to be effective upon the transfer of the Mitchell Plant to WPCo. In April 2014, APCo and WPCo also filed a request with the FERC for approval to transfer AGR's one-half interest in the Mitchell Plant to WPCo. Upon transfer of the Mitchell Plant to WPCo, WPCo will no longer purchase power from AGR.

	APCo IGCC Plant

	As of March 31, 2014, APCo deferred for future recovery pre-construction IGCC costs of approximately $9 million applicable to its West Virginia jurisdiction, approximately $2 million applicable to its FERC jurisdiction and approximately $10 million applicable to its Virginia jurisdiction. In March 2014, APCo submitted a request to the Virginia SCC as part of the 2014 Virginia Biennial Base Rate Case to amortize the Virginia jurisdictional share of these costs over two years. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.
	2013 Virginia Transmission Rate Adjustment Clause (transmission RAC)

	In December 2013, APCo filed with the Virginia SCC to increase its transmission RAC revenues by $50 million annually to be effective May 2014. In March 2014, the Virginia SCC issued an order approving a stipulation agreement between APCo and the Virginia SCC staff increasing the transmission RAC revenues by $49 million annually, subject to true-up, effective May 2014. Pursuant to the order, the Virginia SCC staff will audit APCo's transmission RAC under-recoveries and report its findings and recommendations in testimony in APCo's next transmission RAC proceeding in 2015.

	2014 Virginia Biennial Base Rate Case

	In March 2014, APCo filed a generation and distribution base rate biennial review with the Virginia SCC. In accordance with a Virginia statute, APCo did not request a change in base rates as its Virginia retail combined rate of return on common equity for 2012 and 2013 is within the statutory range of the approved return on common equity of 10.9%. The filing included a request to decrease generation depreciation rates, effective February 2015, primarily due to changes in the expected service lives of various generating units and the extended recovery through 2040 of the net book value of certain planned 2015 plant retirements. Additionally, the filing included a request to amortize $7 million annually for two years, beginning February 2015, related to certain deferred costs. A hearing at the Virginia SCC is scheduled for September 2014. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

	4. RATE MATTERS

	As discussed in the 2013 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2013 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2014 and updates the 2013 Annual Report.

	Regulatory Assets Not Yet Being Recovered
						APCo
						March 31,			December 31,
						2014			2013
		Noncurrent Regulatory Assets				(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Not Earning a Return
			Storm Related Costs			$	65,206		$	65,206
			IGCC Pre-Construction Costs				20,528			-
			Expanded Net Energy Charge - Coal Inventory				18,818			20,528
			Mountaineer Carbon Capture and Storage
				Product Validation Facility			13,264			13,264
			Virginia Demand Response Program Costs				5,897			5,012
			Transmission Agreement Phase-In				3,450			3,313
			Virginia Environmental Rate Adjustment Clause				1,941			2,440
			Mountaineer Carbon Capture and Storage
				Commercial Scale Facility			1,287			1,287
			Other Regulatory Assets Not Yet Being Recovered				513			168
		Total Regulatory Assets Not Yet Being Recovered				$	130,904		$	111,218
	If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
	APCo Rate Matters
	WPCo Merger with APCo

	In December 2011, APCo and WPCo filed an application with the WVPSC requesting authority to merge WPCo into APCo. In December 2012, APCo and WPCo filed merger applications with the Virginia SCC and the FERC. In April 2013, the FERC approved the merger. Also in December 2012, APCo and WPCo filed requests with the Virginia SCC and the WVPSC for approval to transfer at net book value to APCo a two-thirds interest in Amos Plant, Unit 3 and a one-half interest in the Mitchell Plant. In June 2013, the WVPSC issued an order consolidating the merger case with APCo's plant asset transfer case. In July 2013, the Virginia SCC approved the merger of WPCo into APCo and the transfer of the two-thirds interest in the Amos Plant, Unit 3 to APCo but denied the proposed transfer of the one-half interest in the Mitchell Plant to APCo. In December 2013, the WVPSC issued an order that deferred ruling on the merger of WPCo into APCo. The order also directed APCo and WPCo to submit a plan with the WVPSC identifying a course of action to serve the load of WPCo. See the “Plant Transfer” section of APCo Rate Matters. The feasibility of the merger remains under review.
Indiana Michigan Power Co [Member]	'
Rate Matters	'
	I&M Rate Matters

	2011 Indiana Base Rate Case

	In February 2013, the IURC issued an order that granted an $85 million annual increase in base rates based upon a return on common equity of 10.2% and adjusted the authorized annual increase in base rates to $92 million in March 2013. In March 2013, the Indiana Office of Utility Consumer Counselor (OUCC) filed an appeal of the order with the Indiana Court of Appeals. In March 2014, the Indiana Court of Appeals upheld the February 2013 IURC order. In April 2014, the OUCC filed an appeal to the Indiana Supreme Court related to the inclusion of a prepaid pension asset in rate base. If any part of the IURC order is overturned by the Indiana Supreme Court, it could reduce future net income and cash flows.
	Cook Plant Life Cycle Management Project (LCM Project)

	In April and May 2012, I&M filed a petition with the IURC and the MPSC, respectively, for approval of the LCM Project, which consists of a group of capital projects to ensure the safe and reliable operations of the Cook Plant through its licensed life (2034 for Unit 1 and 2037 for Unit 2). The estimated cost of the LCM Project is $1.2 billion to be incurred through 2018, excluding AFUDC. As of March 31, 2014, I&M has incurred costs of $405 million related to the LCM Project, including AFUDC.

	In July 2013, the IURC approved I&M's proposed project with the exception of an estimated $23 million related to certain items that might accommodate a future potential power uprate which the IURC stated I&M could seek recovery of in a subsequent base rate case. I&M will recover approved costs through an LCM rider which will be determined in semi-annual proceedings. The IURC authorized deferral accounting for costs incurred related to certain projects effective January 2012 to the extent such costs are not reflected in rates. In December 2013, the IURC issued an interim order authorizing the implementation of LCM rider rates effective January 2014, subject to reconciliation upon the issuance of a final order by the IURC.

	In January 2013, the MPSC approved a Certificate of Need (CON) for the LCM Project and authorized deferral accounting for costs incurred related to the approved projects effective January 2013 until these costs are included in rates. In February 2013, intervenors filed appeals with the Michigan Court of Appeals objecting to the issuance of the CON as well as the amount of the CON related to the LCM Project.

	If I&M is not ultimately permitted to recover its LCM Project costs, it could reduce future net income and cash flows and impact financial condition.
	Tanners Creek Plant, Units 1 - 4

	In 2011, I&M announced that it would retire Tanners Creek Plant, Units 1-3 by June 2015 to comply with proposed environmental regulations. In September 2013, I&M announced that Tanners Creek Plant, Unit 4 would also be retired in mid-2015 rather than being converted from coal to natural gas. I&M is currently recovering depreciation and a return on the net book value of the Tanners Creek Plant in base rates and plans to seek recovery of all of the plant's retirement related costs in its next Indiana and Michigan base rate cases.

	In December 2013, I&M filed an application with the MPSC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and Tanners Creek Plant due to the retirement of the Tanners Creek Plant in 2015. Upon the retirement of the Tanners Creek Plant, I&M proposes that the net book value of the Tanners Creek Plant will be recovered over the remaining life of the Rockport Plant. I&M requested to have the impact of these new depreciation rates incorporated into the rates set in its next rate case. The new depreciation rates are expected to result in a decrease in I&M's Michigan jurisdictional electric depreciation expense which I&M proposes to implement in the month following a MPSC order in the revised depreciation case. A hearing at the MPSC is scheduled for September 2014.

	As of March 31, 2014, the net book value of the Tanners Creek Plant was $334 million, before cost of removal, including materials and supplies inventory and CWIP. If I&M is ultimately not permitted to fully recover its net book value of the Tanners Creek Plant and its retirement-related costs, it could reduce future net income and cash flows and impact financial condition.
	4. RATE MATTERS

	As discussed in the 2013 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2013 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2014 and updates the 2013 Annual Report.

	Regulatory Assets Not Yet Being Recovered
						I&M
						March 31,			December 31,
						2014			2013
		Noncurrent Regulatory Assets				(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Not Earning a Return
			Indiana Under-Recovered Capacity Costs			$	28,149		$	21,945
			Cook Plant Turbine				4,238			3,452
			Stranded Costs on Abandoned Plants				3,897			3,896
			Storm Related Costs				751			1,836
			Indiana Deferred Cook Plant Life Cycle Management Project Costs				-			4,093
			Other Regulatory Assets Not Yet Being Recovered				694			164
		Total Regulatory Assets Not Yet Being Recovered				$	37,729		$	35,386
	If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
Ohio Power Co [Member]	'
Rate Matters	'
	OPCo Rate Matters

	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. OPCo collected the 2009 annualized revenue increase over the last nine months of 2009. 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. The PUCO's March 2009 order was appealed to the Supreme Court of Ohio, which issued an opinion and remanded certain issues back to the PUCO.

	In October 2011, the PUCO issued an order in the remand proceeding. As a result, OPCo ceased collection of POLR billings in November 2011 and recorded a write-off in 2011 related to POLR collections for the period June 2011 through October 2011. In February 2012, the Ohio Consumers' Counsel and the IEU filed appeals of that order with the Supreme Court of Ohio challenging various issues, including the PUCO's refusal to order retrospective relief concerning the POLR charges collected during 2009 – 2011 and various aspects of the approved environmental carrying charge, which, if ordered, could reduce OPCo's net deferred fuel costs up to the total balance. As of March 31, 2014, OPCo's net deferred fuel balance was $426 million, excluding unrecognized equity carrying costs. In February 2014, the Supreme Court of Ohio affirmed the PUCO's decision and rejected all appeals filed by the OCC and the IEU. In February 2014, the IEU filed for reconsideration of the Supreme Court of Ohio decision.

	In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo filed an appeal at the Supreme Court of Ohio related to the PUCO decision in the PIRR proceeding claiming a long-term debt rate modified the previously adjudicated 2009 – 2011 ESP order, which granted a weighted average cost of capital rate. In November 2012, the IEU and the OCC filed appeals regarding the PUCO decision in the PIRR proceeding. These appeals principally argued that the PUCO should have reduced the deferred fuel balance to reflect the prior “improper” collection of POLR revenues which could reduce OPCo's net deferred fuel balance up to the total balance. These intervenors' appeals also argued that carrying costs should be reduced due to an accumulated deferred income tax credit which, as of March 31, 2014, could reduce carrying costs by $30 million including $16 million of unrecognized equity carrying costs. A decision from the Supreme Court of Ohio is pending.

	Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the rulings in these proceedings, it could reduce future net income and cash flows and impact financial condition.

	June 2012 – May 2015 ESP Including Capacity Charge

	In August 2012, the PUCO issued an order which adopted and modified a new ESP that establishes base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013.

	In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88/MW day. The OPCo RPM price, which includes reserve margins, is approximately $33/MW day through May 2014 and $148/MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio.
	As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR is being collected from customers at $3.50/MWh through May 2014 and will be collected at $4.00/MWh for the period June 2014 through May 2015, with $1.00/MWh applied to the recovery of deferred capacity costs. As of March 31, 2014, OPCo's incurred deferred capacity costs balance of $348 million, including debt carrying costs, was recorded in Regulatory Assets on the balance sheet.

	In January and March 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order including the implementation of the RSR. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In April and May 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO's ESP order, including the RSR.

	In November 2013, the PUCO issued an order approving OPCo's CBP with modifications. The modifications include the delay of the energy auctions that were originally ordered in the ESP order. As ordered, in February 2014, OPCo conducted an energy-only auction for 10% of the SSO load with delivery beginning April 2014 through May 2015. The PUCO also ordered OPCo to conduct energy-only auctions for an additional 50% of the SSO load with delivery beginning November 2014 through May 2015 and for the remaining 40% of the SSO load for delivery from January 2015 through May 2015. OPCo will conduct energy and capacity auctions for its entire SSO load for delivery starting in June 2015. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. Management believes that these intervenor concerns are without merit. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 – 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo's request to implement riders related to the unbundling of the FAC.

	Proposed June 2015 – May 2018 ESP

	In December 2013, OPCo filed an application with the PUCO to approve an ESP that includes proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider, effective June 2015 through May 2018. This filing is consistent with the PUCO's objective for a full transition from FAC and base generation rates to market. The proposal includes a recommended auction schedule, a return on common equity of 10.65% on capital costs for certain riders and estimates an average decrease in rates of 9% over the three-year term of the plan for customers who receive their RPM and energy auction-based generation through OPCo. Additionally, the application identifies OPCo's intention to submit a separate application to continue the RSR established in the June 2012 – May 2015 ESP in which the unrecovered portion of the deferred capacity costs will continue to be collected at the rate of $4.00/MWh until the balance of the capacity deferrals has been collected. Management intends to file this application in the second quarter of 2014. A hearing at the PUCO in the ESP case is scheduled for June 2014.

	If OPCo is ultimately not permitted to fully collect its ESP rates, including the RSR, its deferred fuel balance and its deferred capacity cost, it could reduce future net income and cash flows and impact financial condition.

	Significantly Excessive Earnings Test (SEET) Filings

	In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo's gridSMART® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In November 2013, OPCo filed its 2011 SEET filing with the PUCO. OPCo was required to file its 2011 SEET filing with the PUCO on a separate CSPCo and OPCo company basis. In March 2014, the PUCO approved a stipulation agreement between OPCo and the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2011 for CSPCo or OPCo.

	In November 2013, OPCo filed its 2012 SEET filing with the PUCO. In April 2014, OPCo entered into a stipulation agreement with the PUCO staff in which both parties agree that there were no significantly excessive earnings in 2012 for OPCo. A hearing at the PUCO related to the 2012 SEET filing is scheduled for April 2014. Management does not believe that there were significantly excessive earnings in 2013 for OPCo.
	Storm Damage Recovery Rider (SDRR)

	In December 2012, OPCo submitted an application with the PUCO to establish initial SDRR rates to recover 2012 incremental storm distribution expenses over twelve months starting with the effective date as approved by the PUCO. In December 2013, a stipulation agreement was reached between OPCo, the PUCO staff and all intervenors except the OCC. The stipulation agreement recommended approval to recover $55 million related to 2012 storm costs over a 12-month period which included a $6 million reduction in the amount of 2012 storm expenses to be recovered. The agreement also provided that carrying charges using a long-term debt rate will be assessed from April 2013 until recovery begins, but no additional carrying charges will accrue during the actual recovery period. In April 2014, the PUCO approved the settlement agreement. Compliance tariffs were filed with the PUCO and new rates were implemented in April 2014.

	2009 Fuel Adjustment Clause Audit

	In January 2012, the PUCO issued an order in OPCo's 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo's under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant's review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition.

	In August 2012, intervenors filed an appeal with the Supreme Court of Ohio claiming the settlement credit ordered by the PUCO should have reflected the remaining gain not already flowed through the FAC with carrying charges, which, if ordered, would be $35 million plus carrying charges. If the Supreme Court of Ohio ultimately determines that additional amounts should benefit ratepayers, it could reduce future net income and cash flows and impact financial condition.
	2010 and 2011 Fuel Adjustment Clause Audits

	The PUCO-selected outside consultant issued its 2010 and 2011 FAC audit reports which included a recommendation that the PUCO reexamine the carrying costs on the deferred FAC balance and determine whether the carrying costs on the balance should be net of accumulated income taxes with the use of a weighted average cost of capital (WACC). The PUCO subsequently ruled in the PIRR proceeding that the fuel clause for these years was approved with a WACC carrying cost and that the carrying costs on the balance should not be net of accumulated income taxes. Hearings at the PUCO were held in November 2013. If the PUCO orders result in a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition. See the 2009 – 2011 ESP section of the “Ohio Electric Security Plan Filing” related to the PUCO order in the PIRR proceeding.
	2012 – 2013 Fuel Adjustment Clause Audits

	In April 2014, the PUCO-selected outside consultant provided its preliminary draft report related to their 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. If the PUCO orders a reduction to the FAC deferral, it could reduce future net income and cash flows and impact financial condition.
	Ormet

	Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In February 2013, Ormet filed Chapter 11 bankruptcy proceedings in the state of Delaware. In October 2013, Ormet announced that it was unable to emerge from bankruptcy and shut down operations effective immediately. Based upon previous PUCO rulings providing rate assistance to Ormet, the PUCO is expected to permit OPCo to recover unpaid Ormet amounts through the Economic Development Rider (EDR), except where recovery from ratepayers is limited to $20 million related to previously deferred payments from Ormet's October and November 2012 power bills. OPCo expects that any additional unpaid generation usage by Ormet will be recoverable as a regulatory asset through the EDR. In February 2014, a stipulation agreement between OPCo and Ormet was filed with the PUCO. The stipulation recommends approval of OPCo's right to fully recover approximately $49 million of foregone revenues through the EDR which, as of March 31, 2014, is recorded in regulatory assets on the balance sheet. Also in February 2014, intervenor comments were filed objecting to full recovery of these foregone revenues. In March 2014, the PUCO issued an order in OPCo's EDR filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals. In April 2014, an intervenor filed testimony objecting to $5 million of the remaining foregone revenues. A hearing at the PUCO related to the stipulation agreement is scheduled for May 2014.

	In addition, in the 2009 – 2011 ESP proceeding, intervenors requested that OPCo be required to refund the Ormet-related revenues under a previous interim arrangement (effective from January 2009 through September 2009) and requested that the PUCO prevent OPCo from collecting Ormet-related revenues in the future. Through September 2009, the last month of the interim arrangement, OPCo had $64 million of deferred FAC costs related to the interim arrangement, excluding $2 million of unrecognized equity carrying costs. The PUCO did not take any action on this request. The intervenors raised this issue again in response to OPCo's November 2009 filing to approve recovery of the deferral under the interim agreement.

	To the extent amounts discussed above are not recoverable, it could reduce future net income and cash flows and impact financial condition.
	Ohio IGCC Plant

	In March 2005, OPCo filed an application with the PUCO seeking authority to recover costs of building and operating an IGCC power plant. As of March 31, 2014, OPCo has collected $24 million in pre-construction costs authorized in a June 2006 PUCO order. Intervenors have filed motions with the PUCO requesting that OPCo refund all collected pre-construction costs to Ohio ratepayers with interest.

	Management cannot predict the outcome of this proceeding concerning the Ohio IGCC plant or what effect, if any, this proceeding could have on future net income and cash flows. However, if OPCo is required to refund pre-construction costs collected, it could reduce future net income and cash flows and impact financial condition.
4. RATE MATTERS

As discussed in the 2013 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2013 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2014 and updates the 2013 Annual Report.

Regulatory Assets Not Yet Being Recovered
					OPCo
					March 31,			December 31,
					2014			2013
	Noncurrent Regulatory Assets				(in thousands)
	Regulatory assets not yet being recovered pending future proceedings:

	Regulatory Assets Currently Earning a Return
		Economic Development Rider			$	-		$	13,854
	Regulatory Assets Currently Not Earning a Return
		Ormet Special Rate Recovery Mechanism				10,483			35,631
		Storm Related Costs				1,635			57,589
	Total Regulatory Assets Not Yet Being Recovered				$	12,118		$	107,074
If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
Corporate Separation

In October 2012, the PUCO issued an order which approved the corporate separation of OPCo's generation assets including the transfer of OPCo's generation assets and associated generation liabilities at net book value to AGR. In June 2013, the IEU filed an appeal with the Supreme Court of Ohio claiming the PUCO order approving the corporate separation was unlawful. A decision from the Supreme Court of Ohio is pending. In December 2013, corporate separation of OPCo's generation assets was completed. If any part of the PUCO order is overturned, it could reduce future net income and cash flows and impact financial condition.
Public Service Co Of Oklahoma [Member]	'
Rate Matters	'
	PSO Rate Matters

	2014 Oklahoma Base Rate Case

	In January 2014, PSO filed a request with the OCC to increase annual base rates by $38 million, based upon a 10.5% return on common equity. This revenue increase includes a proposed increase in depreciation rates of $29 million. In addition, the filing proposed recovery of advanced metering costs through a separate rider over a three-year deployment period requesting $7 million of revenues in year one, increasing to $28 million in year three. The filing also proposed expansion of an existing transmission rider currently recovered in base rates to include additional transmission-related costs that are expected to increase over the next several years.

	In April 2014, OCC Staff and intervenors filed testimony with recommendations that included adjustments to annual base rates ranging from an increase of $16 million to a reduction of $22 million, primarily based upon the determination of depreciation rates and a return on common equity between 9.18% and 9.5%. Additionally, the recommendations did not support the advanced metering rider or the expansion of the transmission rider. A hearing at the OCC is scheduled for June 2014. If the OCC were to disallow any portion of this base rate request, it could reduce future net income and cash flows and impact financial condition.
	4. RATE MATTERS

	As discussed in the 2013 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2013 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2014 and updates the 2013 Annual Report.

	Regulatory Assets Not Yet Being Recovered
						PSO
						March 31,			December 31,
						2014			2013
		Noncurrent Regulatory Assets				(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Not Earning a Return
			Storm Related Costs			$	19,093		$	18,743
			Other Regulatory Assets Not Yet Being Recovered				1,079			845
		Total Regulatory Assets Not Yet Being Recovered				$	20,172		$	19,588
	If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.
Southwestern Electric Power Co [Member]	'
Rate Matters	'
	SWEPCo Rate Matters

	2012 Texas Base Rate Case

	In July 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In October 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant's Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo's recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of March 31, 2014, the net book value of Welsh Plant, Unit 2 was $86 million, before cost of removal, including materials and supplies inventory and CWIP.

	Upon rehearing in January 2014, the PUCT reversed its initial ruling and determined that AFUDC was excluded from the Turk Plant's Texas jurisdictional capital cost cap. As a result, in the fourth quarter of 2013, SWEPCo reversed $114 million of previously recorded regulatory disallowances. The resulting annual base rate increase is approximately $52 million. In March 2014, the PUCT issued an order related to the January 2014 PUCT ruling. This order became final and appealable in April 2014.

	If any part of the PUCT order is overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs of Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition.
	2013 Texas Transmission Cost Recovery Factor Filing

	In December 2013, SWEPCo filed an application to implement its initial transmission cost recovery factor (TCRF) requesting additional annual revenue of $10 million. The TCRF is designed to recover increases from the amounts included in SWEPCo's Texas retail base rates for transmission infrastructure improvement costs and wholesale transmission charges under a tariff approved by the FERC. SWEPCo's application included Turk Plant transmission-related costs. In March 2014, the Administrative Law Judge (ALJ) dismissed this case without prejudice. The ALJ concluded that SWEPCo's application was premature as the PUCT had not completed its ruling on the motions for rehearing of the order in the SWEPCo Texas Base Rate Case in which the baseline values to be used in the TCRF calculation would be established.

	2012 Louisiana Formula Rate Filing

	In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29%) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery of the Louisiana jurisdictional share of the Turk Plant and Stall Unit. The rates are subject to refund based on the staff review of the cost of service and the prudency review of the Turk Plant. The settlement also provided that the LPSC will review base rates in 2014 and 2015 and that SWEPCo will recover non-fuel Turk Plant costs and a full weighted-average cost of capital return on the prudently incurred Turk Plant investment in jurisdictional rate base, effective January 2013. In May 2013, SWEPCo filed testimony in the prudence review of the Turk Plant. If the LPSC orders refunds based upon the pending staff review of the cost of service or the prudence review of the Turk Plant, it could reduce future net income and cash flows and impact financial condition.
	2014 Louisiana Formula Rate Filing

	In April 2014, SWEPCo filed its annual formula rate plan for test year 2013 with the LPSC. The filing included a $5 million annual increase to be effective August 2014. SWEPCo also proposed to increase rates by an additional $15 million annually, effective January 2015, for a total annual increase of $20 million. This additional increase reflects the cost of incremental generation to be used to serve Louisiana customers in 2015 due to the expiration of a purchase power agreement attributable to Louisiana customers. These increases are subject to LPSC staff review. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

	4. RATE MATTERS

	As discussed in the 2013 Annual Report, the Registrant Subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within the 2013 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact net income, cash flows and possibly financial condition. The following discusses ratemaking developments in 2014 and updates the 2013 Annual Report.

	Regulatory Assets Not Yet Being Recovered
						SWEPCo
						March 31,			December 31,
						2014			2013
		Noncurrent Regulatory Assets				(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Not Earning a Return
			Rate Case Expenses			$	7,930		$	7,934
			Mountaineer Carbon Capture and Storage
				Commercial Scale Facility			1,143			1,143
			Other Regulatory Assets Not Yet Being Recovered				2,025			1,951
		Total Regulatory Assets Not Yet Being Recovered				$	11,098		$	11,028
	If these costs are ultimately determined not to be recoverable, it could reduce future net income and cash flows and impact financial condition.

Commitments_Guarantees_and_Con

Commitments, Guarantees and Contingencies	3 Months Ended
	Mar. 31, 2014
Commitments, Guarantees and Contingencies	'
	5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

	We are subject to certain claims and legal actions arising in our ordinary course of business. In addition, our 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 us cannot be predicted. 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 our financial statements. The Commitments, Guarantees and Contingencies note within our 2013 Annual Report should be read in conjunction with this report.
	GUARANTEES

	We record liabilities for guarantees 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

	We enter into standby letters of credit with third parties. As Parent, we issue all of these letters of credit in our ordinary course of business on behalf of our subsidiaries. These letters of credit cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.

	We have two revolving credit facilities totaling $3.5 billion, under which we may issue up to $1.2 billion as letters of credit. As of March 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were $130 million with maturities ranging from June 2014 to April 2015.

	In January 2014, we issued letters of credit under an $85 million uncommitted facility signed in October 2013. As of March 31, 2014, the maximum future payment for letters of credit issued under the uncommitted facility was $75 million with a maturity in July 2014. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility.

	We have $352 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $356 million. The letters of credit have maturities ranging from July 2014 to March 2017.
	Guarantees of Third-Party Obligations

	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, we estimate 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 March 31, 2014, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46 million is recorded in Asset Retirement Obligations on our condensed balance sheets.

	Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause.
	Indemnifications and Other Guarantees

	Contracts

	We enter into several 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, our exposure generally does not exceed the sale price. As of March 31, 2014, there were no material liabilities recorded for any indemnifications.

	Master Lease Agreements

	We 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, we are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2014, the maximum potential loss for these lease agreements was approximately $21 million assuming the fair value of the equipment is zero at the end of the lease term.

	Railcar Lease

	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 $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2014.

	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 approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, assuming the fair value of the equipment is zero at the end of the current five-year lease term. However, we believe that the fair value would produce a sufficient sales price to avoid any loss.
	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, our generation plants and transmission and distribution facilities have used asbestos, polychlorinated biphenyls and other hazardous and nonhazardous materials. We currently incur costs to dispose of these substances safely.

	In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. I&M's reserve is approximately $8 million. As the remediation work is completed, I&M's cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. We cannot predict the amount of additional cost, if any.
	NUCLEAR CONTINGENCIES

	I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. We have 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 generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.
	OPERATIONAL CONTINGENCIES

	Rockport Plant Litigation

	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 our motion to transfer this case to the U.S. District Court for the Southern District of Ohio. Our motion to dismiss the case, filed in October 2013, is pending. We will continue to defend against the claims. We are unable to determine a range of potential losses that are reasonably possible of occurring.

	Natural Gas Markets Lawsuits

	In 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against numerous energy companies, including AEP, alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were also filed in California and in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. AEP (or a subsidiary) is among the companies named as defendants in some of these cases. We settled, received summary judgment or were dismissed from all of these cases. The plaintiffs appealed the Nevada federal district court's dismissal of several cases involving AEP companies to the U.S. Court of Appeals for the Ninth Circuit. In April 2013, the appellate court reversed in part, and affirmed in part, the district court's orders in these cases. The appellate court reversed the district court's holding that the state antitrust claims were preempted by the Natural Gas Act and the order dismissing AEP from two of the cases on personal jurisdiction grounds and affirmed the decision denying leave to the plaintiffs to amend their complaints in two of the cases. AEP filed a motion with the appellate court for rehearing on the issue of whether the district court had personal jurisdiction of AEP in the two referenced cases. That motion was denied. We are considering seeking a review of this issue by the U.S. Supreme Court. Defendants in these cases, including AEP, previously filed a petition seeking further review with the U.S. Supreme Court on the preemption issue, which is pending. We will continue to defend the cases. We believe the provision we have is adequate. We are unable to determine a range of potential losses that are reasonably possible of occurring.
	Wage and Hours Lawsuit

	In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount.

	In March 2014, the federal court granted plaintiffs' motion to conditionally certify the action as a class action. We will continue to defend the case. We are unable to determine a range of potential losses that are reasonably possible of occurring.
Appalachian Power Co [Member]	'
Commitments, Guarantees and Contingencies	'
	5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

	The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2013 Annual Report should be read in conjunction with this report.
	GUARANTEES

	Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

	Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

	Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.
	The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows:
					Bilateral		Maturity of
			Pollution		Letters		Bilateral Letters
		Company	Control Bonds		of Credit		of Credit
			(in thousands)
		APCo	$	229,650	$	232,293	March 2016 to March 2017
		I&M		77,000		77,886	Mar-15
	Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo

	Contracts

	The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2014, 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 the AEP East Companies related to power purchase and sale activity pursuant to the SIA. 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 pursuant to the SIA.
	Master Lease Agreements

	The Registrant Subsidiaries 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 Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2014, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
Indiana Michigan Power Co [Member]	'
Commitments, Guarantees and Contingencies	'
	5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

	The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2013 Annual Report should be read in conjunction with this report.
	GUARANTEES

	Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

	Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

	Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.

	AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit. As of March 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows:
		Company	Amount		Maturity
			(in thousands)
		I&M	$	150	Mar-15
		OPCo		3,081	Jun-14
	The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows:
					Bilateral		Maturity of
			Pollution		Letters		Bilateral Letters
		Company	Control Bonds		of Credit		of Credit
			(in thousands)
		APCo	$	229,650	$	232,293	March 2016 to March 2017
		I&M		77,000		77,886	Mar-15
	Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo

	Contracts

	The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2014, 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 the AEP East Companies related to power purchase and sale activity pursuant to the SIA. 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 pursuant to the SIA.
	Master Lease Agreements

	The Registrant Subsidiaries 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 Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2014, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
	Railcar Lease

	In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2014.

	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 approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, 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.
	ENVIRONMENTAL CONTINGENCIES

	The Comprehensive Environmental Response Compensation and Liability Act (Superfund) and State Remediation – Affecting I&M

	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 Registrant Subsidiaries currently incur costs to dispose of these substances safely.

	In 2008, I&M received a letter from the Michigan Department of Environmental Quality (MDEQ) concerning conditions at a site under state law and requesting I&M take voluntary action necessary to prevent and/or mitigate public harm. I&M started remediation work in accordance with a plan approved by MDEQ. I&M's reserve is approximately $8 million. As the remediation work is completed, I&M's cost may change as new information becomes available concerning either the level of contamination at the site or changes in the scope of remediation required by the MDEQ. Management cannot predict the amount of additional cost, if any.
	NUCLEAR CONTINGENCIES – AFFECTING I&M

	I&M owns and operates the two-unit 2,191 MW Cook Plant under licenses granted by the Nuclear Regulatory Commission. 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 generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial.
	OPERATIONAL CONTINGENCIES

	Rockport Plant Litigation – Affecting 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. The motion to dismiss, filed in October 2013, is pending. Management will continue to defend against the claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Ohio Power Co [Member]	'
Commitments, Guarantees and Contingencies	'
	5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

	The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2013 Annual Report should be read in conjunction with this report.
	GUARANTEES

	Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

	Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

	Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.

	AEP has two revolving credit facilities totaling $3.5 billion, under which up to $1.2 billion may be issued as letters of credit. As of March 31, 2014, the maximum future payments for letters of credit issued under the revolving credit facilities were as follows:
		Company	Amount		Maturity
			(in thousands)
		I&M	$	150	Mar-15
		OPCo		3,081	Jun-14
	Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo

	Contracts

	The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2014, 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 the AEP East Companies related to power purchase and sale activity pursuant to the SIA. 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 pursuant to the SIA.
	Master Lease Agreements

	The Registrant Subsidiaries 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 Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2014, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
Public Service Co Of Oklahoma [Member]	'
Commitments, Guarantees and Contingencies	'
	5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

	The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2013 Annual Report should be read in conjunction with this report.
	GUARANTEES

	Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.
	Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo

	Contracts

	The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2014, 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 the AEP East Companies related to power purchase and sale activity pursuant to the SIA. 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 pursuant to the SIA.
	Master Lease Agreements

	The Registrant Subsidiaries 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 Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2014, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
	Wage and Hours Lawsuit – Affecting PSO

	In August 2013, PSO received an amended complaint filed in the U.S. District Court for the Northern District of Oklahoma by 36 current and former line and warehouse employees alleging that they have been denied overtime pay in violation of the Fair Labor Standards Act. Plaintiffs claim that they are entitled to overtime pay for “on call” time. They allege that restrictions placed on them during on call hours are burdensome enough that they are entitled to compensation for these hours as hours worked. Plaintiffs also filed a motion to conditionally certify this action as a class action, claiming there are an additional 70 individuals similarly situated to plaintiffs. Plaintiffs seek damages in the amount of unpaid overtime over a three-year period and liquidated damages in the same amount.

	In March 2014, the federal court granted plaintiffs' motion to conditionally certify the action as a class action. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring.

Southwestern Electric Power Co [Member]	'
Commitments, Guarantees and Contingencies	'
	5. COMMITMENTS, GUARANTEES AND CONTINGENCIES

	The Registrant Subsidiaries are subject to certain claims and legal actions arising in their ordinary course of business. In addition, their business activities are subject to extensive governmental regulation related to public health and the environment. The ultimate outcome of such pending or potential litigation cannot be predicted. For current proceedings not specifically discussed below, management does not anticipate that the liabilities, if any, arising from such proceedings would have a material effect on the financial statements. The Commitments, Guarantees and Contingencies note within the 2013 Annual Report should be read in conjunction with this report.
	GUARANTEES

	Liabilities for guarantees are recorded in accordance with the accounting guidance for “Guarantees.” There is no collateral held in relation to any guarantees. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

	Letters of Credit – Affecting APCo, I&M, OPCo and SWEPCo

	Certain Registrant Subsidiaries enter into standby letters of credit with third parties. These letters of credit are issued in the ordinary course of business and cover items such as insurance programs, security deposits and debt service reserves.
	Guarantees of Third-Party Obligations – Affecting 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 March 31, 2014, SWEPCo has collected approximately $62 million through a rider for final mine closure and reclamation costs, of which $16 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $46 million is recorded in Asset Retirement Obligations on SWEPCo's condensed balance sheets.

	Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs to customers through its fuel clause.
	Indemnifications and Other Guarantees – Affecting APCo, I&M, OPCo, PSO and SWEPCo

	Contracts

	The Registrant Subsidiaries enter into certain types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, exposure generally does not exceed the sale price. As of March 31, 2014, 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 the AEP East Companies related to power purchase and sale activity pursuant to the SIA. 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 pursuant to the SIA.
	Master Lease Agreements

	The Registrant Subsidiaries 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 Registrant Subsidiaries are committed to pay the difference between the actual fair value and the residual value guarantee. Historically, at the end of the lease term the fair value has been in excess of the unamortized balance. As of March 31, 2014, the maximum potential loss by Registrant Subsidiary for these lease agreements assuming the fair value of the equipment is zero at the end of the lease term was as follows:
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
	Railcar Lease

	In June 2003, AEP Transportation LLC (AEP Transportation), a subsidiary of AEP, entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease is accounted for as an operating lease. In January 2008, AEP Transportation assigned the remaining 848 railcars under the original lease agreement to I&M (390 railcars) and SWEPCo (458 railcars). The assignments are accounted for as operating leases for I&M and SWEPCo. The initial lease term was five years with three consecutive five-year renewal periods for a maximum lease term of twenty years. I&M and SWEPCo intend to renew these leases for the full lease term of twenty years via the renewal options. The future minimum lease obligations are $13 million and $15 million for I&M and SWEPCo, respectively, for the remaining railcars as of March 31, 2014.

	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 approximately 83% under the current five year lease term to 77% at the end of the 20-year term of the projected fair value of the equipment. I&M and SWEPCo have assumed the guarantee under the return-and-sale option. The maximum potential losses related to the guarantee are approximately $9 million and $10 million for I&M and SWEPCo, respectively, 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.

Benefit_Plans

Benefit Plans	3 Months Ended
Benefit Plans	Mar. 31, 2014
Benefit Plans	'
	6. BENEFIT PLANS

	Components of Net Periodic Benefit Cost

	The following table provides the components of our net periodic benefit cost (credit) for the plans for the three months ended March 31, 2014 and 2013:
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in millions)
	Service Cost	$	18	$	17	$	4	$	6
	Interest Cost		55		50		17		18
	Expected Return on Plan Assets		-66		-69		-28		-27
	Amortization of Prior Service Cost (Credit)		1		1		-17		-17
	Amortization of Net Actuarial Loss		31		46		5		16
	Net Periodic Benefit Cost (Credit)	$	39	$	45	$	-19	$	-4
Appalachian Power Co [Member]	'
Benefit Plans	'
	6. BENEFIT PLANS

	The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

	Components of Net Periodic Benefit Cost

	The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three months ended March 31, 2014 and 2013:
	APCo
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	1,759	$	1,543	$	362	$	641
	Interest Cost		7,406		6,916		3,197		3,363
	Expected Return on Plan Assets		-8,482		-9,260		-4,633		-4,536
	Amortization of Prior Service Cost (Credit)		50		49		-2,513		-2,512
	Amortization of Net Actuarial Loss		4,148		6,256		1,146		3,062
	Net Periodic Benefit Cost (Credit)	$	4,881	$	5,504	$	-2,441	$	18
Indiana Michigan Power Co [Member]	'
Benefit Plans	'
	6. BENEFIT PLANS

	The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

	Components of Net Periodic Benefit Cost

	The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three months ended March 31, 2014 and 2013:
	I&M
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	2,517	$	2,184	$	487	$	805
	Interest Cost		6,573		6,025		1,909		2,055
	Expected Return on Plan Assets		-7,748		-8,207		-3,364		-3,296
	Amortization of Prior Service Cost (Credit)		49		49		-2,355		-2,355
	Amortization of Net Actuarial Loss		3,646		5,422		592		1,882
	Net Periodic Benefit Cost (Credit)	$	5,037	$	5,473	$	-2,731	$	-909
Ohio Power Co [Member]	'
Benefit Plans	'
	6. BENEFIT PLANS

	The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

	Components of Net Periodic Benefit Cost

	The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three months ended March 31, 2014 and 2013:
	OPCo
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	1,285	$	2,372	$	256	$	1,300
	Interest Cost		5,526		10,292		1,901		4,447
	Expected Return on Plan Assets		-6,607		-15,141		-3,380		-6,238
	Amortization of Prior Service Cost (Credit)		39		71		-1,731		-3,231
	Amortization of Net Actuarial Loss		3,106		9,309		595		4,041
	Net Periodic Benefit Cost (Credit)	$	3,349	$	6,903	$	-2,359	$	319
Public Service Co Of Oklahoma [Member]	'
Benefit Plans	'
	6. BENEFIT PLANS

	The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

	Components of Net Periodic Benefit Cost

	The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three months ended March 31, 2014 and 2013:
	PSO
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	1,302	$	1,391	$	210	$	343
	Interest Cost		3,014		2,748		893		948
	Expected Return on Plan Assets		-3,651		-3,918		-1,575		-1,522
	Amortization of Prior Service Cost (Credit)		74		74		-1,072		-1,072
	Amortization of Net Actuarial Loss		1,688		2,461		277		869
	Net Periodic Benefit Cost (Credit)	$	2,427	$	2,756	$	-1,267	$	-434
Southwestern Electric Power Co [Member]	'
Benefit Plans	'
	6. BENEFIT PLANS

	The Registrant Subsidiaries participate in an AEP sponsored qualified pension plan and two unfunded nonqualified pension plans. Substantially all employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. The Registrant Subsidiaries also participate in OPEB plans sponsored by AEP to provide health and life insurance benefits for retired employees.

	Components of Net Periodic Benefit Cost

	The following tables provide the components of net periodic benefit cost (credit) by Registrant Subsidiary for the plans for the three months ended March 31, 2014 and 2013:
	SWEPCo
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	1,655	$	1,753	$	253	$	423
	Interest Cost		3,163		2,864		998		1,075
	Expected Return on Plan Assets		-3,857		-4,127		-1,754		-1,720
	Amortization of Prior Service Cost (Credit)		87		87		-1,289		-1,288
	Amortization of Net Actuarial Loss		1,761		2,553		309		982
	Net Periodic Benefit Cost (Credit)	$	2,809	$	3,130	$	-1,483	$	-528

Business_Segments

Business Segments	3 Months Ended
Business Segments	Mar. 31, 2014
Business Segments	'
	7. BUSINESS SEGMENTS

	Our primary business is the generation, transmission and distribution of electricity. Within our Vertically Integrated Utilities segment, we centrally dispatch generation assets and manage our 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.

	During the fourth quarter of 2013, we changed the structure of our internal organization which resulted in a change in the composition of our reportable segments. In accordance with authoritative accounting guidance for segment reporting, prior period financial information has been recast in the financial statements and footnotes to be comparable to the current year presentation of reportable segments.

	Our reportable segments and their related business activities are outlined below:

	Vertically Integrated Utilities


	Generation, transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by AEGCo, APCo, I&M, KGPCo, KPCo, PSO, SWEPCo and WPCo.



	Transmission and Distribution Utilities



	Transmission and distribution of electricity for sale to retail and wholesale customers through assets owned and operated by OPCo, TCC and TNC.
	OPCo purchases energy to serve standard service offer customers, and provides capacity for all connected load.



	AEP Transmission Holdco



	Development, construction and operation of transmission facilities through investments in our wholly-owned transmission only subsidiaries and transmission only joint ventures. These investments have PUCT-approved or FERC-approved returns on equity.



	Generation & Marketing



	Nonregulated generation in ERCOT and PJM.
	Marketing, risk management and retail activities in ERCOT, PJM and MISO.


	AEP River Operations


	Commercial barging operation that transports liquids, coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers.


	The remainder of our activities is presented as Corporate and Other. While not considered a reportable segment, Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.

	The tables below present our reportable segment information for the three months ended March 31, 2014 and 2013 and balance sheet information as of March 31, 2014 and December 31, 2013. These amounts include certain estimates and allocations where necessary.
								Transmission
					Vertically			and			AEP			Generation						Corporate
					Integrated			Distribution			Transmission			&			AEP River			and Other			Reconciling
					Utilities			Utilities			Holdco			Marketing			Operations			(a)			Adjustments				Consolidated

					(in millions)
	Three Months Ended March 31, 2014
	Revenues from:
			External Customers		$	2,549	(b)	$	1,161		$	12		$	821	(b)	$	146		$	10		$	-51	(c)		$	4,648
			Other Operating Segments			37	(b)		54			16			430	(b)		19			16			-572				-
	Total Revenues				$	2,586		$	1,215		$	28		$	1,251		$	165		$	26		$	-623			$	4,648

	Net Income (Loss)				$	279		$	97		$	24		$	163		$	3		$	-5		$	-			$	561

							Transmission
				Vertically			and			AEP			Generation						Corporate
				Integrated			Distribution			Transmission			&			AEP River			and Other			Reconciling
				Utilities			Utilities			Holdco			Marketing			Operations			(a)			Adjustments				Consolidated

				(in millions)
Three Months Ended March 31, 2013
Revenues from:
		External Customers		$	2,356		$	1,090		$	3		$	258		$	128		$	5		$	-14	(c)		$	3,826
		Other Operating Segments			159			44			5			662			5			13			-888				-
Total Revenues				$	2,515		$	1,134		$	8		$	920		$	133		$	18		$	-902			$	3,826

Net Income (Loss)				$	181		$	87		$	12		$	85		$	-2		$	1		$	-			$	364
							Transmission
				Vertically			and			AEP			Generation						Corporate			Reconciling
				Integrated			Distribution			Transmission			&			AEP River			and Other			Adjustments
				Utilities			Utilities			Holdco			Marketing			Operations			(a)			(d)				Consolidated

				(in millions)
31-Mar-14
Total Property, Plant and Equipment				$	37,923		$	12,339		$	1,842		$	8,302		$	639		$	321		$	-272			$	61,094
Accumulated Depreciation and
	Amortization				12,424			3,382			13			3,460			197			176			-88				19,564
Total Property, Plant and
	Equipment - Net			$	25,499		$	8,957		$	1,829		$	4,842		$	442		$	145		$	-184			$	41,530

Total Assets				$	32,997		$	13,899		$	2,460		$	6,354		$	659		$	20,275		$	-19,606	(e)		$	57,038

							Transmission
				Vertically			and			AEP			Generation						Corporate			Reconciling
				Integrated			Distribution			Transmission			&			AEP River			and Other			Adjustments
				Utilities			Utilities			Holdco			Marketing			Operations			(a)			(d)				Consolidated

				(in millions)
31-Dec-13
Total Property, Plant and Equipment				$	37,545		$	12,143		$	1,636		$	8,277		$	638		$	315		$	-269			$	60,285
Accumulated Depreciation and
	Amortization				12,250			3,342			10			3,409			189			173			-85				19,288
Total Property, Plant and
	Equipment - Net			$	25,295		$	8,801		$	1,626		$	4,868		$	449		$	142		$	-184			$	40,997

Total Assets				$	32,791		$	14,165		$	2,245		$	6,426		$	673		$	19,645		$	-19,531	(e)		$	56,414
(a) Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense 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.
(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.
Appalachian Power Co [Member]	'
Business Segments	'
	7. BUSINESS SEGMENTS

	The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Indiana Michigan Power Co [Member]	'
Business Segments	'
	7. BUSINESS SEGMENTS

	The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Ohio Power Co [Member]	'
Business Segments	'
	7. BUSINESS SEGMENTS

	The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Public Service Co Of Oklahoma [Member]	'
Business Segments	'
	7. BUSINESS SEGMENTS

	The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Southwestern Electric Power Co [Member]	'
Business Segments	'
	7. BUSINESS SEGMENTS

	The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business. The Registrant Subsidiaries' other activities are insignificant. The Registrant Subsidiaries' operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

Derivatives_and_Hedging

Derivatives and Hedging	3 Months Ended
Derivatives and Hedging	Mar. 31, 2014
Derivatives and Hedging	'
	8. DERIVATIVES AND HEDGING

	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risks using derivative instruments.
	STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

	Risk Management Strategies

	Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact. To accomplish our objectives, we 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.

	We enter into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.

	The following table represents the gross notional volume of our outstanding derivative contracts as of March 31, 2014 and December 31, 2013:
		Notional Volume of Derivative Instruments

					Volume
					March 31,			December 31,			Unit of
					2014			2013			Measure
		Primary Risk Exposure			(in millions)
		Commodity:
			Power			320			406		MWhs
			Coal			4			4		Tons
			Natural Gas			123			127		MMBtus
			Heating Oil and Gasoline			4			6		Gallons
			Interest Rate		$	192		$	191		USD

		Interest Rate and Foreign Currency			$	819		$	820		USD
	Fair Value Hedging Strategies

	We enter 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 our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. We do not hedge all commodity price risk.

	Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. During the three months ended March 31, 2013, we designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. We do not hedge all fuel price risk.

	We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure.

	At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. We do not hedge all foreign currency exposure.
	ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

	The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed 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 our derivative instruments, we also 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 our 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 our risk management contracts.

	According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2014 and December 31, 2013 condensed balance sheets, we netted $19 million and $4 million, respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $17 million and $13 million, respectively, of cash collateral paid to third parties against short-term and long-term risk management liabilities.

	The following tables represent the gross fair value impact of our derivative activity on our condensed balance sheets as of March 31, 2014 and December 31, 2013:
	Fair Value of Derivative Instruments
	31-Mar-14

														Gross Amounts		Gross			Net Amounts of
				Risk Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign				Liabilities		Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in millions)
	Current Risk Management Assets			$	442		$	23		$	4		$	469		$	-344		$	125
	Long-term Risk Management Assets				342			5			-			347			-81			266
	Total Assets				784			28			4			816			-425			391

Current Risk Management Liabilities				384			16			1			401			-341			60
Long-term Risk Management Liabilities				205			4			13			222			-85			137
Total Liabilities				589			20			14			623			-426			197

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	195		$	8		$	-10		$	193		$	1		$	194

Fair Value of Derivative Instruments
31-Dec-13

												Gross Amounts			Gross			Net Amounts of
			Risk Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in millions)
Current Risk Management Assets			$	347		$	12		$	4		$	363		$	-203		$	160
Long-term Risk Management Assets				368			3			-			371			-74			297
Total Assets				715			15			4			734			-277			457

Current Risk Management Liabilities				292			11			1			304			-214			90
Long-term Risk Management Liabilities				237			3			15			255			-78			177
Total Liabilities				529			14			16			559			-292			267

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	186		$	1		$	-12		$	175		$	15		$	190
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed 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." Amounts also include de-designated risk management contracts.
(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 table below presents our activity of derivative risk management contracts for the three months ended March 31, 2014 and 2013:
	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2014 and 2013

	Location of Gain (Loss)		2014				2013
			(in millions)
	Vertically Integrated Utilities Revenues		$	18		$	6
	Generation & Marketing Revenues			32			16
	Regulatory Assets (a)			-			2
	Regulatory Liabilities (a)			89			-6
	Total Gain on Risk Management Contracts		$	139		$	18
(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed 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 condensed statements of income on an accrual basis.

Our 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, we designate 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies

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.

We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income. During the three months ended March 31, 2014, we recognized gains of $2 million on our hedging instruments and offsetting losses of $2 million on our long-term debt. During the three months ended March 31, 2013, we recognized losses of $1 million on our hedging instruments and offsetting gains of $1 million on our long-term debt. During the three months ended March 31, 2014 and 2013, hedge ineffectiveness was immaterial.
Accounting for Cash Flow Hedging Strategies

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2014 and 2013, we designated power, coal and natural gas derivatives as cash flow hedges.

We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income. During the three months ended March 31, 2013, we designated heating oil and gasoline derivatives as cash flow hedges. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014.

We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2014 and 2013, we designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2014 and 2013, we did not designate any foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all cash flow hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets and the reasons for changes in cash flow hedges for the three months ended March 31, 2014 and 2013, see Note 3.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were:
	Impact of Cash Flow Hedges on the Condensed Balance Sheet
	31-Mar-14

								Interest Rate
								and Foreign
					Commodity			Currency			Total
					(in millions)
	Hedging Assets (a)				$	13		$	-		$	13
	Hedging Liabilities (a)					5			2			7
	AOCI Gain (Loss) Net of Tax					4			-22			-18
	Portion Expected to be Reclassified to Net
		Income During the Next Twelve Months				3			-4			-1

	Impact of Cash Flow Hedges on the Condensed Balance Sheet
	31-Dec-13

								Interest Rate
								and Foreign
					Commodity			Currency			Total
					(in millions)
	Hedging Assets (a)				$	7		$	-		$	7
	Hedging Liabilities (a)					6			2			8
	AOCI Gain (Loss) Net of Tax					-			-23			-23
	Portion Expected to be Reclassified to Net
		Income During the Next Twelve Months				-			-4			-4
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ from the estimate above due to market price changes. As of March 31, 2014, the maximum length of time that we are hedging (with contracts subject to the accounting guidance for “Derivatives and Hedging”) our exposure to variability in future cash flows related to forecasted transactions was 41 months.
Credit Risk

We limit credit risk in our 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. We use Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When we use standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs), a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, and guaranties for contractual obligations, we are obligated to post an additional amount of collateral if our credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral. The following table represents: (a) our fair value of such derivative contracts, (b) the amount of collateral we would have been required to post for all derivative and non-derivative contracts and guaranties for contractual obligations if our credit ratings had declined below a specified rating threshold and (c) how much was attributable to RTO and ISO activities as of March 31, 2014 and December 31, 2013:
				March 31,			December 31,
				2014			2013
				(in millions)
	Liabilities for Derivative Contracts with Credit Downgrade Triggers			$	2		$	3
	Amount of Collateral AEP Subsidiaries Would Have Been
		Required to Post			144			33
	Amount Attributable to RTO and ISO Activities				38			28
In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts. The following table represents: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral we have posted and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering our contractual netting arrangements as of March 31, 2014 and December 31, 2013:
			March 31,			December 31,
			2014			2013
			(in millions)
	Liabilities for Contracts with Cross Default Provisions Prior to Contractual
	Netting Arrangements		$	225		$	293
	Amount of Cash Collateral Posted			-			1
	Additional Settlement Liability if Cross Default Provision is Triggered			177			235
Appalachian Power Co [Member]	'
Derivatives and Hedging	'
	8. DERIVATIVES AND HEDGING

	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.

	The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of March 31, 2014 and December 31, 2013:
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2014 and December 31, 2013 condensed balance sheets, the Registrant Subsidiaries 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:
				31-Mar-14						31-Dec-13
				Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
				Received			Paid			Received			Paid
				Netted Against			Netted Against			Netted Against			Netted Against
				Risk Management			Risk Management			Risk Management			Risk Management
	Company			Assets			Liabilities			Assets			Liabilities
				(in thousands)
	APCo			$	32		$	1,362		$	-		$	2,993
	I&M				21			924			-			2,030
	OPCo				3			-			-			-
	PSO				1			-			-			1
	SWEPCo				2			-			-			3
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013:
APCo
Fair Value of Derivative Instruments
31-Mar-14

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	34,483		$	224		$	-		$	34,707		$	-18,735		$	15,972
Long-term Risk Management Assets				17,304			-			-			17,304			-3,291			14,013
Total Assets				51,787			224			-			52,011			-22,026			29,985

Current Risk Management Liabilities				24,273			90			-			24,363			-19,727			4,636
Long-term Risk Management Liabilities				11,558			-			-			11,558			-3,629			7,929
Total Liabilities				35,831			90			-			35,921			-23,356			12,565

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	15,956		$	134		$	-		$	16,090		$	1,330		$	17,420

APCo
Fair Value of Derivative Instruments
31-Dec-13

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	46,431		$	389		$	-		$	46,820		$	-25,649		$	21,171
Long-term Risk Management Assets				20,948			-			-			20,948			-4,000			16,948
Total Assets				67,379			389			-			67,768			-29,649			38,119

Current Risk Management Liabilities				37,010			313			-			37,323			-28,431			8,892
Long-term Risk Management Liabilities				14,452			-			-			14,452			-4,211			10,241
Total Liabilities				51,462			313			-			51,775			-32,642			19,133

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	15,917		$	76		$	-		$	15,993		$	2,993		$	18,986
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed 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 Registrant Subsidiaries' activity of derivative risk management contracts for the three months ended March 31, 2014 and 2013:
	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2014

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
	Sales to AEP Affiliates					-			-221			-			221			-
	Regulatory Assets (a)					4			-			-			2			3
	Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
	Total Gain on Risk Management
		Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2013

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
	Regulatory Assets (a)					-			486			-1,205			2,010			271
	Regulatory Liabilities (a)					-466			-5,182			-			1			96
	Total Gain on Risk Management
		Contracts			$	213		$	251		$	509		$	2,058		$	395

	(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
			or noncurrent on the condensed 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies

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.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any fair value hedging strategies.
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 Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2014 and 2013, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2014 and 2013, I&M designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three months ended March 31, 2014 and 2013, see Note 3.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were:
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Mar-14

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
	I&M				142			-			51			-			61			-15,566
	OPCo				-			-			-			-			-			6,631
	PSO				-			-			-			-			-			5,512
	SWEPCo				-			-			-			-			-			-12,736
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
										Maximum Term for
							Interest Rate			Exposure to
							and Foreign			Variability of Future
	Company			Commodity			Currency			Cash Flows
				(in thousands)						(in months)
	APCo			$	87		$	-682			2
	I&M				61			-1,426			2
	OPCo				-			1,372			-
	PSO				-			759			-
	SWEPCo				-			-2,267			-
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Dec-13

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
	I&M				216			-			194			-			46			-15,976
	OPCo				162			-			-			-			105			6,974
	PSO				84			-			-			-			57			5,701
	SWEPCo				97			-			-			-			66			-13,304
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
							Interest Rate
							and Foreign
	Company			Commodity			Currency
				(in thousands)
	APCo			$	94		$	-806
	I&M				46			-1,568
	OPCo				105			1,363
	PSO				57			759
	SWEPCo				66			-2,267
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

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

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	285		$	5,254		$	4,774
	I&M				190			3,560			3,238
	OPCo				78			-			-
	PSO				132			4,156			-
	SWEPCo				167			145			-
				31-Dec-13
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	575		$	2,747		$	2,539
	I&M				390			1,863			1,722
	OPCo				349			-			-
	PSO				-			2,930			410
	SWEPCo				-			713			519
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	16,375		$	-		$	12,865
	I&M				11,107			-			8,726
	OPCo				-			-			-
	PSO				-			-			-
	SWEPCo				-			-			-

				31-Dec-13
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	19,648		$	-		$	18,568
	I&M				13,326			-			12,594
	OPCo				-			-			-
	PSO				3			-			3
	SWEPCo				3			-			3
Indiana Michigan Power Co [Member]	'
Derivatives and Hedging	'
	8. DERIVATIVES AND HEDGING

	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.

	The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of March 31, 2014 and December 31, 2013:
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2014 and December 31, 2013 condensed balance sheets, the Registrant Subsidiaries 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:
				31-Mar-14						31-Dec-13
				Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
				Received			Paid			Received			Paid
				Netted Against			Netted Against			Netted Against			Netted Against
				Risk Management			Risk Management			Risk Management			Risk Management
	Company			Assets			Liabilities			Assets			Liabilities
				(in thousands)
	APCo			$	32		$	1,362		$	-		$	2,993
	I&M				21			924			-			2,030
	OPCo				3			-			-			-
	PSO				1			-			-			1
	SWEPCo				2			-			-			3
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013:
I&M
Fair Value of Derivative Instruments
31-Mar-14

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	26,273		$	152		$	-		$	26,425		$	-13,867		$	12,558
Long-term Risk Management Assets				11,737			-			-			11,737			-2,232			9,505
Total Assets				38,010			152			-			38,162			-16,099			22,063

Current Risk Management Liabilities				18,614			61			-			18,675			-14,541			4,134
Long-term Risk Management Liabilities				7,839			-			-			7,839			-2,461			5,378
Total Liabilities				26,453			61			-			26,514			-17,002			9,512

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	11,557		$	91		$	-		$	11,648		$	903		$	12,551

I&M
Fair Value of Derivative Instruments
31-Dec-13

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	33,229		$	234		$	-		$	33,463		$	-18,075		$	15,388
Long-term Risk Management Assets				14,208			-			-			14,208			-2,713			11,495
Total Assets				47,437			234			-			47,671			-20,788			26,883

Current Risk Management Liabilities				26,779			212			-			26,991			-19,962			7,029
Long-term Risk Management Liabilities				9,802			-			-			9,802			-2,856			6,946
Total Liabilities				36,581			212			-			36,793			-22,818			13,975

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	10,856		$	22		$	-		$	10,878		$	2,030		$	12,908
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed 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 Registrant Subsidiaries' activity of derivative risk management contracts for the three months ended March 31, 2014 and 2013:
	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2014

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
	Sales to AEP Affiliates					-			-221			-			221			-
	Regulatory Assets (a)					4			-			-			2			3
	Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
	Total Gain on Risk Management
		Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2013

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
	Regulatory Assets (a)					-			486			-1,205			2,010			271
	Regulatory Liabilities (a)					-466			-5,182			-			1			96
	Total Gain on Risk Management
		Contracts			$	213		$	251		$	509		$	2,058		$	395

	(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
			or noncurrent on the condensed 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies

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.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any fair value hedging strategies.
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 Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2014 and 2013, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2014 and 2013, I&M designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three months ended March 31, 2014 and 2013, see Note 3.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were:
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Mar-14

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
	I&M				142			-			51			-			61			-15,566
	OPCo				-			-			-			-			-			6,631
	PSO				-			-			-			-			-			5,512
	SWEPCo				-			-			-			-			-			-12,736
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
										Maximum Term for
							Interest Rate			Exposure to
							and Foreign			Variability of Future
	Company			Commodity			Currency			Cash Flows
				(in thousands)						(in months)
	APCo			$	87		$	-682			2
	I&M				61			-1,426			2
	OPCo				-			1,372			-
	PSO				-			759			-
	SWEPCo				-			-2,267			-
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Dec-13

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
	I&M				216			-			194			-			46			-15,976
	OPCo				162			-			-			-			105			6,974
	PSO				84			-			-			-			57			5,701
	SWEPCo				97			-			-			-			66			-13,304
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
							Interest Rate
							and Foreign
	Company			Commodity			Currency
				(in thousands)
	APCo			$	94		$	-806
	I&M				46			-1,568
	OPCo				105			1,363
	PSO				57			759
	SWEPCo				66			-2,267
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

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

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	285		$	5,254		$	4,774
	I&M				190			3,560			3,238
	OPCo				78			-			-
	PSO				132			4,156			-
	SWEPCo				167			145			-
				31-Dec-13
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	575		$	2,747		$	2,539
	I&M				390			1,863			1,722
	OPCo				349			-			-
	PSO				-			2,930			410
	SWEPCo				-			713			519
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	16,375		$	-		$	12,865
	I&M				11,107			-			8,726
	OPCo				-			-			-
	PSO				-			-			-
	SWEPCo				-			-			-

				31-Dec-13
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	19,648		$	-		$	18,568
	I&M				13,326			-			12,594
	OPCo				-			-			-
	PSO				3			-			3
	SWEPCo				3			-			3
Ohio Power Co [Member]	'
Derivatives and Hedging	'
	8. DERIVATIVES AND HEDGING

	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.

	The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of March 31, 2014 and December 31, 2013:
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2014 and December 31, 2013 condensed balance sheets, the Registrant Subsidiaries 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:
				31-Mar-14						31-Dec-13
				Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
				Received			Paid			Received			Paid
				Netted Against			Netted Against			Netted Against			Netted Against
				Risk Management			Risk Management			Risk Management			Risk Management
	Company			Assets			Liabilities			Assets			Liabilities
				(in thousands)
	APCo			$	32		$	1,362		$	-		$	2,993
	I&M				21			924			-			2,030
	OPCo				3			-			-			-
	PSO				1			-			-			1
	SWEPCo				2			-			-			3
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013:
OPCo
Fair Value of Derivative Instruments
31-Mar-14

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	4,066		$	-		$	-		$	4,066		$	-86		$	3,980
Long-term Risk Management Assets				-			-			-			-			-			-
Total Assets				4,066			-			-			4,066			-86			3,980

Current Risk Management Liabilities				83			-			-			83			-83			-
Long-term Risk Management Liabilities				-			-			-			-			-			-
Total Liabilities				83			-			-			83			-83			-

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	3,983		$	-		$	-		$	3,983		$	-3		$	3,980

OPCo
Fair Value of Derivative Instruments
31-Dec-13

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	3,269		$	162		$	-		$	3,431		$	-349		$	3,082
Long-term Risk Management Assets				-			-			-			-			-			-
Total Assets				3,269			162			-			3,431			-349			3,082

Current Risk Management Liabilities				349			-			-			349			-349			-
Long-term Risk Management Liabilities				-			-			-			-			-			-
Total Liabilities				349			-			-			349			-349			-

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	2,920		$	162		$	-		$	3,082		$	-		$	3,082
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed 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 Registrant Subsidiaries' activity of derivative risk management contracts for the three months ended March 31, 2014 and 2013:
	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2014

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
	Sales to AEP Affiliates					-			-221			-			221			-
	Regulatory Assets (a)					4			-			-			2			3
	Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
	Total Gain on Risk Management
		Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2013

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
	Regulatory Assets (a)					-			486			-1,205			2,010			271
	Regulatory Liabilities (a)					-466			-5,182			-			1			96
	Total Gain on Risk Management
		Contracts			$	213		$	251		$	509		$	2,058		$	395

	(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
			or noncurrent on the condensed 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies

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.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any fair value hedging strategies.
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 Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2014 and 2013, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2014 and 2013, I&M designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three months ended March 31, 2014 and 2013, see Note 3.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were:
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Mar-14

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
	I&M				142			-			51			-			61			-15,566
	OPCo				-			-			-			-			-			6,631
	PSO				-			-			-			-			-			5,512
	SWEPCo				-			-			-			-			-			-12,736
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
										Maximum Term for
							Interest Rate			Exposure to
							and Foreign			Variability of Future
	Company			Commodity			Currency			Cash Flows
				(in thousands)						(in months)
	APCo			$	87		$	-682			2
	I&M				61			-1,426			2
	OPCo				-			1,372			-
	PSO				-			759			-
	SWEPCo				-			-2,267			-
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Dec-13

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
	I&M				216			-			194			-			46			-15,976
	OPCo				162			-			-			-			105			6,974
	PSO				84			-			-			-			57			5,701
	SWEPCo				97			-			-			-			66			-13,304
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
							Interest Rate
							and Foreign
	Company			Commodity			Currency
				(in thousands)
	APCo			$	94		$	-806
	I&M				46			-1,568
	OPCo				105			1,363
	PSO				57			759
	SWEPCo				66			-2,267
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

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

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	285		$	5,254		$	4,774
	I&M				190			3,560			3,238
	OPCo				78			-			-
	PSO				132			4,156			-
	SWEPCo				167			145			-
				31-Dec-13
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	575		$	2,747		$	2,539
	I&M				390			1,863			1,722
	OPCo				349			-			-
	PSO				-			2,930			410
	SWEPCo				-			713			519
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	16,375		$	-		$	12,865
	I&M				11,107			-			8,726
	OPCo				-			-			-
	PSO				-			-			-
	SWEPCo				-			-			-

				31-Dec-13
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	19,648		$	-		$	18,568
	I&M				13,326			-			12,594
	OPCo				-			-			-
	PSO				3			-			3
	SWEPCo				3			-			3
Public Service Co Of Oklahoma [Member]	'
Derivatives and Hedging	'
	8. DERIVATIVES AND HEDGING

	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.

	The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of March 31, 2014 and December 31, 2013:
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2014 and December 31, 2013 condensed balance sheets, the Registrant Subsidiaries 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:
				31-Mar-14						31-Dec-13
				Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
				Received			Paid			Received			Paid
				Netted Against			Netted Against			Netted Against			Netted Against
				Risk Management			Risk Management			Risk Management			Risk Management
	Company			Assets			Liabilities			Assets			Liabilities
				(in thousands)
	APCo			$	32		$	1,362		$	-		$	2,993
	I&M				21			924			-			2,030
	OPCo				3			-			-			-
	PSO				1			-			-			1
	SWEPCo				2			-			-			3
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013:
PSO
Fair Value of Derivative Instruments
31-Mar-14

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	1,403		$	-		$	-		$	1,403		$	-54		$	1,349
Long-term Risk Management Assets				-			-			-			-			-			-
Total Assets				1,403			-			-			1,403			-54			1,349

Current Risk Management Liabilities				136			-			-			136			-53			83
Long-term Risk Management Liabilities				-			-			-			-			-			-
Total Liabilities				136			-			-			136			-53			83

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	1,267		$	-		$	-		$	1,267		$	-1		$	1,266

PSO
Fair Value of Derivative Instruments
31-Dec-13

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	1,078		$	84		$	-		$	1,162		$	5		$	1,167
Long-term Risk Management Assets				-			-			-			-			-			-
Total Assets				1,078			84			-			1,162			5			1,167

Current Risk Management Liabilities				81			-			-			81			4			85
Long-term Risk Management Liabilities				-			-			-			-			-			-
Total Liabilities				81			-			-			81			4			85

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	997		$	84		$	-		$	1,081		$	1		$	1,082
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed 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 Registrant Subsidiaries' activity of derivative risk management contracts for the three months ended March 31, 2014 and 2013:
	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2014

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
	Sales to AEP Affiliates					-			-221			-			221			-
	Regulatory Assets (a)					4			-			-			2			3
	Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
	Total Gain on Risk Management
		Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2013

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
	Regulatory Assets (a)					-			486			-1,205			2,010			271
	Regulatory Liabilities (a)					-466			-5,182			-			1			96
	Total Gain on Risk Management
		Contracts			$	213		$	251		$	509		$	2,058		$	395

	(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
			or noncurrent on the condensed 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies

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.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any fair value hedging strategies.
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 Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2014 and 2013, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2014 and 2013, I&M designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three months ended March 31, 2014 and 2013, see Note 3.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were:
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Mar-14

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
	I&M				142			-			51			-			61			-15,566
	OPCo				-			-			-			-			-			6,631
	PSO				-			-			-			-			-			5,512
	SWEPCo				-			-			-			-			-			-12,736
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
										Maximum Term for
							Interest Rate			Exposure to
							and Foreign			Variability of Future
	Company			Commodity			Currency			Cash Flows
				(in thousands)						(in months)
	APCo			$	87		$	-682			2
	I&M				61			-1,426			2
	OPCo				-			1,372			-
	PSO				-			759			-
	SWEPCo				-			-2,267			-
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Dec-13

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
	I&M				216			-			194			-			46			-15,976
	OPCo				162			-			-			-			105			6,974
	PSO				84			-			-			-			57			5,701
	SWEPCo				97			-			-			-			66			-13,304
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
							Interest Rate
							and Foreign
	Company			Commodity			Currency
				(in thousands)
	APCo			$	94		$	-806
	I&M				46			-1,568
	OPCo				105			1,363
	PSO				57			759
	SWEPCo				66			-2,267
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

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

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	285		$	5,254		$	4,774
	I&M				190			3,560			3,238
	OPCo				78			-			-
	PSO				132			4,156			-
	SWEPCo				167			145			-
				31-Dec-13
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	575		$	2,747		$	2,539
	I&M				390			1,863			1,722
	OPCo				349			-			-
	PSO				-			2,930			410
	SWEPCo				-			713			519
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	16,375		$	-		$	12,865
	I&M				11,107			-			8,726
	OPCo				-			-			-
	PSO				-			-			-
	SWEPCo				-			-			-

				31-Dec-13
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	19,648		$	-		$	18,568
	I&M				13,326			-			12,594
	OPCo				-			-			-
	PSO				3			-			3
	SWEPCo				3			-			3
Southwestern Electric Power Co [Member]	'
Derivatives and Hedging	'
	8. DERIVATIVES AND HEDGING

	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.

	The following tables represent the gross notional volume of the Registrant Subsidiaries' outstanding derivative contracts as of March 31, 2014 and December 31, 2013:
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries are required to post or receive cash collateral based on third party contractual agreements and risk profiles. For the March 31, 2014 and December 31, 2013 condensed balance sheets, the Registrant Subsidiaries 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:
				31-Mar-14						31-Dec-13
				Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
				Received			Paid			Received			Paid
				Netted Against			Netted Against			Netted Against			Netted Against
				Risk Management			Risk Management			Risk Management			Risk Management
	Company			Assets			Liabilities			Assets			Liabilities
				(in thousands)
	APCo			$	32		$	1,362		$	-		$	2,993
	I&M				21			924			-			2,030
	OPCo				3			-			-			-
	PSO				1			-			-			1
	SWEPCo				2			-			-			3
The following tables represent the gross fair value of the Registrant Subsidiaries' derivative activity on the condensed balance sheets as of March 31, 2014 and December 31, 2013:
SWEPCo
Fair Value of Derivative Instruments
31-Mar-14

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	2,080		$	-		$	-		$	2,080		$	-173		$	1,907
Long-term Risk Management Assets				-			-			-			-			-			-
Total Assets				2,080			-			-			2,080			-173			1,907

Current Risk Management Liabilities				171			-			-			171			-171			-
Long-term Risk Management Liabilities				-			-			-			-			-			-
Total Liabilities				171			-			-			171			-171			-

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	1,909		$	-		$	-		$	1,909		$	-2		$	1,907

SWEPCo
Fair Value of Derivative Instruments
31-Dec-13

			Risk									Gross Amounts			Gross			Net Amounts of
			Management									of Risk			Amounts			Assets/Liabilities
			Contracts			Hedging Contracts						Management			Offset in the			Presented in the
									Interest Rate			Assets/			Statement of			Statement of
									and Foreign			Liabilities			Financial			Financial
Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

			(in thousands)
Current Risk Management Assets			$	1,233		$	97		$	-		$	1,330		$	-151		$	1,179
Long-term Risk Management Assets				-			-			-			-			-			-
Total Assets				1,233			97			-			1,330			-151			1,179

Current Risk Management Liabilities				154			-			-			154			-154			-
Long-term Risk Management Liabilities				-			-			-			-			-			-
Total Liabilities				154			-			-			154			-154			-

Total MTM Derivative Contract Net
	Assets (Liabilities)		$	1,079		$	97		$	-		$	1,176		$	3		$	1,179
(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed 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 Registrant Subsidiaries' activity of derivative risk management contracts for the three months ended March 31, 2014 and 2013:
	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2014

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
	Sales to AEP Affiliates					-			-221			-			221			-
	Regulatory Assets (a)					4			-			-			2			3
	Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
	Total Gain on Risk Management
		Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

	Amount of Gain (Loss) Recognized on
	Risk Management Contracts
	For the Three Months Ended March 31, 2013

	Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
	Electric Generation, Transmission and
		Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
	Regulatory Assets (a)					-			486			-1,205			2,010			271
	Regulatory Liabilities (a)					-466			-5,182			-			1			96
	Total Gain on Risk Management
		Contracts			$	213		$	251		$	509		$	2,058		$	395

	(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
			or noncurrent on the condensed 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
Accounting for Fair Value Hedging Strategies

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.

The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any fair value hedging strategies.
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 Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged. During the three months ended March 31, 2014 and 2013, APCo, I&M and OPCo designated power, coal and natural gas derivatives as cash flow hedges.

The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income. During the three months ended March 31, 2013, the Registrant Subsidiaries designated heating oil and gasoline derivatives as cash flow hedges. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014.

The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur. During the three months ended March 31, 2014 and 2013, I&M designated interest rate derivatives as cash flow hedges.

The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships. During the three months ended March 31, 2014 and 2013, the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges.

During the three months ended March 31, 2014 and 2013, hedge ineffectiveness was immaterial or nonexistent for all of the hedge strategies disclosed above.

For details on designated, effective cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets and the reasons for changes in cash flow hedges for the three months ended March 31, 2014 and 2013, see Note 3.
Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of March 31, 2014 and December 31, 2013 were:
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Mar-14

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
	I&M				142			-			51			-			61			-15,566
	OPCo				-			-			-			-			-			6,631
	PSO				-			-			-			-			-			5,512
	SWEPCo				-			-			-			-			-			-12,736
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
										Maximum Term for
							Interest Rate			Exposure to
							and Foreign			Variability of Future
	Company			Commodity			Currency			Cash Flows
				(in thousands)						(in months)
	APCo			$	87		$	-682			2
	I&M				61			-1,426			2
	OPCo				-			1,372			-
	PSO				-			759			-
	SWEPCo				-			-2,267			-
	Impact of Cash Flow Hedges on the Registrant Subsidiaries’
	Condensed Balance Sheets
	31-Dec-13

				Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
							Interest Rate						Interest Rate						Interest Rate
							and Foreign						and Foreign						and Foreign
	Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
				(in thousands)
	APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
	I&M				216			-			194			-			46			-15,976
	OPCo				162			-			-			-			105			6,974
	PSO				84			-			-			-			57			5,701
	SWEPCo				97			-			-			-			66			-13,304
				Expected to be Reclassified to
				Net Income During the Next
				Twelve Months
							Interest Rate
							and Foreign
	Company			Commodity			Currency
				(in thousands)
	APCo			$	94		$	-806
	I&M				46			-1,568
	OPCo				105			1,363
	PSO				57			759
	SWEPCo				66			-2,267
(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.

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

AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Collateral Triggering Events

Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade. The following tables represent: (a) the Registrant Subsidiaries' fair values of such derivative contracts, (b) the amount of collateral the Registrant Subsidiaries would have been required to post for all derivative and non-derivative contracts if credit ratings of the Registrant Subsidiaries had declined below investment grade and (c) how much was attributable to RTO and ISO activities as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	285		$	5,254		$	4,774
	I&M				190			3,560			3,238
	OPCo				78			-			-
	PSO				132			4,156			-
	SWEPCo				167			145			-
				31-Dec-13
				Liabilities for			Amount of Collateral the			Amount
				Derivative Contracts			Registrant Subsidiaries			Attributable to
				with Credit			Would Have Been			RTO and ISO
	Company			Downgrade Triggers			Required to Post			Activities
				(in thousands)
	APCo			$	575		$	2,747		$	2,539
	I&M				390			1,863			1,722
	OPCo				349			-			-
	PSO				-			2,930			410
	SWEPCo				-			713			519
In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts. The following tables represent: (a) the fair value of these derivative liabilities subject to cross-default provisions prior to consideration of contractual netting arrangements, (b) the amount this exposure has been reduced by cash collateral posted by the Registrant Subsidiaries and (c) if a cross-default provision would have been triggered, the settlement amount that would be required after considering the Registrant Subsidiaries' contractual netting arrangements as of March 31, 2014 and December 31, 2013:
				31-Mar-14
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	16,375		$	-		$	12,865
	I&M				11,107			-			8,726
	OPCo				-			-			-
	PSO				-			-			-
	SWEPCo				-			-			-

				31-Dec-13
				Liabilities for						Additional
				Contracts with Cross						Settlement
				Default Provisions						Liability if Cross
				Prior to Contractual			Amount of Cash			Default Provision
	Company			Netting Arrangements			Collateral Posted			is Triggered
				(in thousands)
	APCo			$	19,648		$	-		$	18,568
	I&M				13,326			-			12,594
	OPCo				-			-			-
	PSO				3			-			3
	SWEPCo				3			-			3

Fair_Value_Measurements

Fair Value Measurements	3 Months Ended
Fair Value Measurements	Mar. 31, 2014
Fair Value Measurements	'
	9. FAIR VALUE MEASUREMENTS

	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our 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 daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to AEP Energy Supply's President and Vice President.

	For our 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. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, we include these locations 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 our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market. A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	We utilize our trustee's external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee's operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

	Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

	The book values and fair values of Long-term Debt as of March 31, 2014 and December 31, 2013 are summarized in the following table:
				31-Mar-14						31-Dec-13
				Book Value			Fair Value			Book Value			Fair Value
				(in millions)
		Long-term Debt		$	18,087		$	19,738		$	18,377		$	19,672
	Fair Value Measurements of Other Temporary Investments

	Other Temporary Investments include funds held by trustees primarily for the payment of securitization bonds and Securities Available for Sale, including marketable securities that we intend to hold for less than one year and investments by our protected cell of EIS.

	The following is a summary of Other Temporary Investments:
						31-Mar-14
									Gross			Gross			Estimated
									Unrealized			Unrealized			Fair
		Other Temporary Investments				Cost			Gains			Losses			Value
						(in millions)
		Restricted Cash (a)				$	206		$	-		$	-		$	206
		Fixed Income Securities:
			Mutual Funds				80			-			-			80
		Equity Securities - Mutual Funds					13			11			-			24
		Total Other Temporary Investments				$	299		$	11		$	-		$	310

						31-Dec-13
									Gross			Gross			Estimated
									Unrealized			Unrealized			Fair
		Other Temporary Investments				Cost			Gains			Losses			Value
						(in millions)
		Restricted Cash (a)				$	250		$	-		$	-		$	250
		Fixed Income Securities:
			Mutual Funds				80			-			-			80
		Equity Securities - Mutual Funds					12			11			-			23
		Total Other Temporary Investments				$	342		$	11		$	-		$	353

		(a)		Primarily represents amounts held for the repayment of debt.
	The following table provides the activity for our fixed income and equity securities within Other Temporary Investments for the three months ended March 31, 2014 and 2013:
			Three Months Ended March 31,
			2014			2013
			(in millions)
		Proceeds from Investment Sales	$	-		$	-
		Purchases of Investments		1			11
		Gross Realized Gains on Investment Sales		-			-
		Gross Realized Losses on Investment Sales		-			-
	As of March 31, 2014 and December 31, 2013, we had no Other Temporary Investments with an unrealized loss position. As of March 31, 2014, fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates.

	For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three months ended March 31, 2014 and 2013, see Note 3.
	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

	Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us 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 or its affiliates.
Withdrawals permitted only for payment of decommissioning costs and trust expenses.


We maintain trust records for each regulatory jurisdiction. 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 trust funds for decommissioning nuclear facilities and for the disposal of SNF 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 fixed income 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 equity and fixed income investments held in these trusts and generally intends to sell fixed income 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 the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction's liabilities. Regulatory approval is required to withdraw decommissioning funds.

The following is a summary of nuclear trust fund investments as of March 31, 2014 and December 31, 2013:
				31-Mar-14									31-Dec-13
				Estimated			Gross			Other-Than-			Estimated			Gross			Other-Than-
				Fair			Unrealized			Temporary			Fair			Unrealized			Temporary
				Value			Gains			Impairments			Value			Gains			Impairments
				(in millions)
	Cash and Cash Equivalents			$	12		$	-		$	-		$	19		$	-		$	-
	Fixed Income Securities:
		United States Government			606			31			-4			609			26			-4
		Corporate Debt			43			4			-1			37			2			-1
		State and Local Government			281			1			-			255			1			-
		Subtotal Fixed Income Securities			930			36			-5			901			29			-5
	Equity Securities - Domestic				1,020			514			-80			1,012			506			-82
	Spent Nuclear Fuel and
		Decommissioning Trusts		$	1,962		$	550		$	-85		$	1,932		$	535		$	-87
The following table provides the securities activity within the decommissioning and SNF trusts for the three months ended March 31, 2014 and 2013:
		Three Months Ended March 31,
		2014			2013
		(in millions)
	Proceeds from Investment Sales	$	148		$	168
	Purchases of Investments		164			185
	Gross Realized Gains on Investment Sales		8			3
	Gross Realized Losses on Investment Sales		1			2
The adjusted cost of fixed income securities was $894 million and $872 million as of March 31, 2014 and December 31, 2013, respectively. The adjusted cost of equity securities was $506 million and $506 million as of March 31, 2014 and December 31, 2013, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2014 was as follows:
		Fair Value of
		Fixed Income
		Securities
		(in millions)
	Within 1 year	$	82
	1 year – 5 years		386
	5 years – 10 years		193
	After 10 years		269
	Total	$	930
Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, our financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. 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. Our 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 our valuation techniques.
Assets and Liabilities Measured at Fair Value on a Recurring Basis
31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

Assets:			(in millions)

Cash and Cash Equivalents (a)			$	16		$	1		$	-		$	275		$	292

Other Temporary Investments
Restricted Cash (a)				187			7			-			12			206
Fixed Income Securities:
	Mutual Funds			80			-			-			-			80
Equity Securities - Mutual Funds (b)				24			-			-			-			24
Total Other Temporary Investments				291			7			-			12			310

Risk Management Assets
Risk Management Commodity Contracts (c) (d)				20			586			128			-364			370
Cash Flow Hedges:
	Commodity Hedges (c)			-			21			2			-10			13
Fair Value Hedges				-			2			-			2			4
De-designated Risk Management Contracts (e)				-			-			-			4			4
Total Risk Management Assets				20			609			130			-368			391

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (f)				3			-			-			9			12
Fixed Income Securities:
	United States Government			-			606			-			-			606
	Corporate Debt			-			43			-			-			43
	State and Local Government			-			281			-			-			281
		Subtotal Fixed Income Securities		-			930			-			-			930
Equity Securities - Domestic (b)				1,020			-			-			-			1,020
Total Spent Nuclear Fuel and Decommissioning Trusts				1,023			930			-			9			1,962

Total Assets			$	1,350		$	1,547		$	130		$	-72		$	2,955

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (d)			$	30		$	485		$	25		$	-362		$	178
Cash Flow Hedges:
	Commodity Hedges (c)			-			15			-			-10			5
	Interest Rate/Foreign Currency Hedges			-			2			-			-			2
Fair Value Hedges				-			10			-			2			12
Total Risk Management Liabilities			$	30		$	512		$	25		$	-370		$	197
Assets and Liabilities Measured at Fair Value on a Recurring Basis
31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

Assets:			(in millions)

Cash and Cash Equivalents (a)			$	16		$	1		$	-		$	101		$	118

Other Temporary Investments
Restricted Cash (a)				231			8			-			11			250
Fixed Income Securities:
	Mutual Funds			80			-			-			-			80
Equity Securities - Mutual Funds (b)				23			-			-			-			23
Total Other Temporary Investments				334			8			-			11			353

Risk Management Assets
Risk Management Commodity Contracts (c) (g)				22			549			142			-273			440
Cash Flow Hedges:
	Commodity Hedges (c)			-			15			-			-8			7
Fair Value Hedges				-			1			-			3			4
De-designated Risk Management Contracts (e)				-			-			-			6			6
Total Risk Management Assets				22			565			142			-272			457

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (f)				8			-			-			11			19
Fixed Income Securities:
	United States Government			-			609			-			-			609
	Corporate Debt			-			37			-			-			37
	State and Local Government			-			255			-			-			255
		Subtotal Fixed Income Securities		-			901			-			-			901
Equity Securities - Domestic (b)				1,012			-			-			-			1,012
Total Spent Nuclear Fuel and Decommissioning Trusts				1,020			901			-			11			1,932

Total Assets			$	1,392		$	1,475		$	142		$	-149		$	2,860

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)			$	30		$	475		$	22		$	-282		$	245
Cash Flow Hedges:
	Commodity Hedges (c)			-			11			3			-8			6
	Interest Rate/Foreign Currency Hedges			-			2			-			-			2
Fair Value Hedges				-			11			-			3			14
Total Risk Management Liabilities			$	30		$	499		$	25		$	-287		$	267
(a) Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b) Amounts represent publicly traded equity securities and equity-based mutual funds.
(c) Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''
(d) The March 31, 2014 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 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.
(e) Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.'' At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts.
(f) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(g) The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives and other investments classified as Level 3 in the fair value hierarchy:
				Net Risk Management
	Three Months Ended March 31, 2014			Assets (Liabilities)
				(in millions)
	Balance as of December 31, 2013			$	117
	Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)				84
	Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
		Relating to Assets Still Held at the Reporting Date (a)			-10
	Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income				9
	Purchases, Issuances and Settlements (c)				-100
	Transfers into Level 3 (d) (e)				-4
	Transfers out of Level 3 (e) (f)				-2
	Changes in Fair Value Allocated to Regulated Jurisdictions (g)				11
	Balance as of March 31, 2014			$	105
				Net Risk Management
	Three Months Ended March 31, 2013			Assets (Liabilities)
				(in millions)
	Balance as of December 31, 2012			$	86
	Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)				-4
	Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
		Relating to Assets Still Held at the Reporting Date (a)			-5
	Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income				1
	Purchases, Issuances and Settlements (c)				-6
	Transfers into Level 3 (d) (e)				6
	Transfers out of Level 3 (e) (f)				-
	Changes in Fair Value Allocated to Regulated Jurisdictions (g)				-2
	Balance as of March 31, 2013			$	76
(a) Included in revenues on the condensed statements of income.
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c) Represents the settlement of risk management commodity contracts for the reporting period.
(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) Represents existing assets or liabilities that were previously categorized as Level 3.
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
The following tables quantify the significant unobservable inputs used in developing the fair value of our Level 3 positions as of March 31, 2014 and December 31, 2013:
Significant Unobservable Inputs
31-Mar-14

		Fair Value						Valuation		Significant		Input/Range
		Assets			Liabilities			Technique		Unobservable Input		Low			High
		(in millions)
Energy Contracts		$	116		$	23		Discounted Cash Flow		Forward Market Price (a)		$	1.45		$	131.46
										Counterparty Credit Risk (b)			315
FTRs			14			2		Discounted Cash Flow		Forward Market Price (a)			-5.05			9.17
Total		$	130		$	25
Significant Unobservable Inputs
31-Dec-13

		Fair Value						Valuation		Significant		Input/Range
		Assets			Liabilities			Technique		Unobservable Input		Low			High
		(in millions)
Energy Contracts		$	132		$	22		Discounted Cash Flow		Forward Market Price (a)		$	11.42		$	120.72
										Counterparty Credit Risk (b)			316
FTRs			10			3		Discounted Cash Flow		Forward Market Price (a)			-5.1			10.44
Total		$	142		$	25
(a) Represents market prices in dollars per MWh.
(b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Appalachian Power Co [Member]	'
Fair Value Measurements	'
	9. FAIR VALUE MEASUREMENTS

	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

	The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of March 31, 2014 and December 31, 2013 are summarized in the following table:
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
	Fair Value Measurements of Financial Assets and Liabilities

	The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. 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.

	APCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Restricted Cash for Securitized Funding (a)		$	13,536		$	-		$	-		$	36		$	13,572

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			393			37,854			10,508			-18,979			29,776
	Cash Flow Hedges:
		Commodity Hedges (b)		-			224			-			-15			209
	Total Risk Management Assets			393			38,078			10,508			-18,994			29,985

	Total Assets:		$	13,929		$	38,078		$	10,508		$	-18,958		$	43,557

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	306		$	29,386		$	3,107		$	-20,309		$	12,490
	Cash Flow Hedges:
		Commodity Hedges (b)		-			90			-			-15			75
	Total Risk Management Liabilities		$	306		$	29,476		$	3,107		$	-20,324		$	12,565
	APCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Restricted Cash for Securitized Funding (a)		$	2,714		$	-		$	-		$	36		$	2,750

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			827			54,448			12,097			-29,616			37,756
Cash Flow Hedges:
	Commodity Hedges (b)		-			389			-			-26			363
Total Risk Management Assets			827			54,837			12,097			-29,642			38,119

Total Assets		$	3,541		$	54,837		$	12,097		$	-29,606		$	40,869

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	700		$	49,220		$	1,535		$	-32,609		$	18,846
Cash Flow Hedges:
	Commodity Hedges (b)		-			313			-			-26			287
Total Risk Management Liabilities		$	700		$	49,533		$	1,535		$	-32,635		$	19,133
(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

	Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
	Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
	Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			3,289			2,052			4,065			349			442
	Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
	Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				257			179			366			-			-
	Transfers into Level 3 (d) (e)				632			434			888			-			-
	Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			-1,123			-732			490			-			-
	Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
(a) Included in revenues on the condensed statements of income.
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c) Represents the settlement of risk management commodity contracts for the reporting period.
(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) Represents existing assets or liabilities that were previously categorized as Level 3.
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of March 31, 2014 and December 31, 2013:
	Significant Unobservable Inputs
	31-Mar-14
	APCo
			Fair Value						Valuation		Significant		Forward Price Range
			Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
			(in thousands)
	Energy Contracts		$	6,454		$	2,822		Discounted Cash Flow		Forward Market Price		$	13.34		$	59.6
	FTRs			4,054			285		Discounted Cash Flow		Forward Market Price			-5.05			9.17
	Total		$	10,508		$	3,107

	Significant Unobservable Inputs
	31-Dec-13
	APCo
			Fair Value						Valuation		Significant		Forward Price Range
			Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
			(in thousands)
	Energy Contracts		$	9,359		$	960		Discounted Cash Flow		Forward Market Price		$	13.04		$	80.5
	FTRs			2,738			575		Discounted Cash Flow		Forward Market Price			-5.1			10.44
	Total		$	12,097		$	1,535
(a) Represents market prices in dollars per MWh.
Indiana Michigan Power Co [Member]	'
Fair Value Measurements	'
	9. FAIR VALUE MEASUREMENTS

	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	AEP utilizes its trustee's external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP's investment managers review and validate the prices utilized by the trustee to determine fair value. AEP's management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee's operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

	Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

	The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of March 31, 2014 and December 31, 2013 are summarized in the following table:
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

	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 or its affiliates.
	Withdrawals permitted only for payment of decommissioning costs and trust expenses.


	I&M maintains trust records for each regulatory jurisdiction. 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 trust funds for decommissioning nuclear facilities and for the disposal of SNF 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 fixed income 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 equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction's liabilities. Regulatory approval is required to withdraw decommissioning funds.

	The following is a summary of nuclear trust fund investments as of March 31, 2014 and December 31, 2013:
					31-Mar-14									31-Dec-13
					Estimated			Gross			Other-Than-			Estimated			Gross			Other-Than-
					Fair			Unrealized			Temporary			Fair			Unrealized			Temporary
					Value			Gains			Impairments			Value			Gains			Impairments
					(in thousands)
		Cash and Cash Equivalents			$	12,439		$	-		$	-		$	18,804		$	-		$	-
		Fixed Income Securities:
			United States Government			606,228			31,666			-3,621			608,875			26,114			-3,824
			Corporate Debt			42,727			3,223			-1,097			36,782			2,450			-1,123
			State and Local Government			280,612			972			-345			254,638			748			-370
			Subtotal Fixed Income Securities			929,567			35,861			-5,063			900,295			29,312			-5,317
		Equity Securities - Domestic				1,020,145			513,803			-79,563			1,012,511			505,538			-81,677
		Spent Nuclear Fuel and
			Decommissioning Trusts		$	1,962,151		$	549,664		$	-84,626		$	1,931,610		$	534,850		$	-86,994
	The following table provides the securities activity within the decommissioning and SNF trusts for the three months ended March 31, 2014 and 2013:
			Three Months Ended March 31,
			2014			2013
			(in thousands)
		Proceeds from Investment Sales	$	147,700		$	167,670
		Purchases of Investments		164,511			184,299
		Gross Realized Gains on Investment Sales		8,141			3,323
		Gross Realized Losses on Investment Sales		874			2,315
	The adjusted cost of fixed income securities was $894 million and $872 million as of March 31, 2014 and December 31, 2013, respectively. The adjusted cost of equity securities was $506 million and $506 million as of March 31, 2014 and December 31, 2013, respectively.
The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of March 31, 2014 was as follows:
		Fair Value of
		Fixed Income
		Securities

		(in thousands)
	Within 1 year	$	82,190
	1 year – 5 years		386,173
	5 years – 10 years		193,018
	After 10 years		268,186
	Total	$	929,567
Fair Value Measurements of Financial Assets and Liabilities

The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. 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.

I&M
Assets and Liabilities Measured at Fair Value on a Recurring Basis
31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			$	267		$	28,746		$	6,945		$	-14,037		$	21,921
Cash Flow Hedges:
	Commodity Hedges (b)			-			152			-			-10			142
Total Risk Management Assets				267			28,898			6,945			-14,047			22,063

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				3,576			-			-			8,863			12,439
Fixed Income Securities:
	United States Government			-			606,228			-			-			606,228
	Corporate Debt			-			42,727			-			-			42,727
	State and Local Government			-			280,612			-			-			280,612
		Subtotal Fixed Income Securities		-			929,567			-			-			929,567
Equity Securities - Domestic (e)				1,020,145			-			-			-			1,020,145
Total Spent Nuclear Fuel and Decommissioning Trusts				1,023,721			929,567			-			8,863			1,962,151

Total Assets			$	1,023,988		$	958,465		$	6,945		$	-5,184		$	1,984,214

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)			$	208		$	22,089		$	2,104		$	-14,940		$	9,461
Cash Flow Hedges:
	Commodity Hedges (b)			-			61			-			-10			51
Total Risk Management Liabilities			$	208		$	22,150		$	2,104		$	-14,950		$	9,512
I&M
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

Assets:			(in thousands)

Risk Management Assets
Risk Management Commodity Contracts (b) (c)			$	561		$	38,667		$	8,205		$	-20,766		$	26,667
Cash Flow Hedges:
	Commodity Hedges (b)			-			234			-			-18			216
Total Risk Management Assets				561			38,901			8,205			-20,784			26,883

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (d)				8,082			-			-			10,722			18,804
Fixed Income Securities:
	United States Government			-			608,875			-			-			608,875
	Corporate Debt			-			36,782			-			-			36,782
	State and Local Government			-			254,638			-			-			254,638
		Subtotal Fixed Income Securities		-			900,295			-			-			900,295
Equity Securities - Domestic (e)				1,012,511			-			-			-			1,012,511
Total Spent Nuclear Fuel and Decommissioning Trusts				1,020,593			900,295			-			10,722			1,931,610

Total Assets			$	1,021,154		$	939,196		$	8,205		$	-10,062		$	1,958,493

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)			$	475		$	35,061		$	1,041		$	-22,796		$	13,781
Cash Flow Hedges:
	Commodity Hedges (b)			-			212			-			-18			194
Total Risk Management Liabilities			$	475		$	35,273		$	1,041		$	-22,814		$	13,975
(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

	Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
	Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
	Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			3,289			2,052			4,065			349			442
	Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
	Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				257			179			366			-			-
	Transfers into Level 3 (d) (e)				632			434			888			-			-
	Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			-1,123			-732			490			-			-
	Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
(a) Included in revenues on the condensed statements of income.
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c) Represents the settlement of risk management commodity contracts for the reporting period.
(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) Represents existing assets or liabilities that were previously categorized as Level 3.
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of March 31, 2014 and December 31, 2013:
	Significant Unobservable Inputs
	31-Mar-14
	I&M
			Fair Value						Valuation		Significant		Forward Price Range
			Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
			(in thousands)
	Energy Contracts		$	4,378		$	1,914		Discounted Cash Flow		Forward Market Price		$	13.34		$	59.6
	FTRs			2,567			190		Discounted Cash Flow		Forward Market Price			-5.05			9.17
	Total		$	6,945		$	2,104

	Significant Unobservable Inputs
	31-Dec-13
	I&M
			Fair Value						Valuation		Significant		Forward Price Range
			Assets			Liabilities			Technique		Unobservable Input (a)		Low			High

			(in thousands)
	Energy Contracts		$	6,348		$	651		Discounted Cash Flow		Forward Market Price		$	13.04		$	80.5
	FTRs			1,857			390		Discounted Cash Flow		Forward Market Price			-5.1			10.44
	Total		$	8,205		$	1,041
(a) Represents market prices in dollars per MWh.
Ohio Power Co [Member]	'
Fair Value Measurements	'
	9. FAIR VALUE MEASUREMENTS

	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

	The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of March 31, 2014 and December 31, 2013 are summarized in the following table:
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
	Fair Value Measurements of Financial Assets and Liabilities

	The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. 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.

	OPCo
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Restricted Cash for Securitized Funding (a)		$	32,054		$	-		$	-		$	12		$	32,066

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			-			76			3,990			-86			3,980

	Total Assets		$	32,054		$	76		$	3,990		$	-74		$	36,046

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	5		$	78		$	-83		$	-
	OPCo
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Restricted Cash for Securitized Funding (a)		$	19,387		$	-		$	-		$	12		$	19,399

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			-			-			3,269			-349			2,920
	Cash Flow Hedges:
		Commodity Hedges (b)		-			162			-			-			162
	Total Risk Management Assets			-			162			3,269			-349			3,082

	Total Assets		$	19,387		$	162		$	3,269		$	-337		$	22,481

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	-		$	-		$	349		$	-349		$	-
(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

	Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
	Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
	Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			3,289			2,052			4,065			349			442
	Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
	Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				257			179			366			-			-
	Transfers into Level 3 (d) (e)				632			434			888			-			-
	Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			-1,123			-732			490			-			-
	Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
(a) Included in revenues on the condensed statements of income.
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c) Represents the settlement of risk management commodity contracts for the reporting period.
(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) Represents existing assets or liabilities that were previously categorized as Level 3.
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of March 31, 2014 and December 31, 2013:
	Significant Unobservable Inputs
	31-Mar-14
	OPCo
			Fair Value						Valuation		Significant		Forward Price Range
			Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
			(in thousands)
	Energy Contracts		$	-		$	-		Discounted Cash Flow		Forward Market Price		$	-		$	-
	FTRs			3,990			78		Discounted Cash Flow		Forward Market Price			-5.05			9.17
	Total		$	3,990		$	78

	Significant Unobservable Inputs
	31-Dec-13
	OPCo
			Fair Value						Valuation		Significant		Forward Price Range
			Assets			Liabilities			Technique		Unobservable Input (a)		Low			High

			(in thousands)
	Energy Contracts		$	-		$	-		Discounted Cash Flow		Forward Market Price		$	-		$	-
	FTRs			3,269			349		Discounted Cash Flow		Forward Market Price			-5.1			10.44
	Total		$	3,269		$	349
(a) Represents market prices in dollars per MWh.
Public Service Co Of Oklahoma [Member]	'
Fair Value Measurements	'
	9. FAIR VALUE MEASUREMENTS

	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

	The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of March 31, 2014 and December 31, 2013 are summarized in the following table:
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
	Fair Value Measurements of Financial Assets and Liabilities

	The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. 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.

	PSO
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)		$	-		$	922		$	481		$	-54		$	1,349

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	4		$	132		$	-53		$	83
	PSO
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)		$	-		$	1,078		$	-		$	5		$	1,083
	Cash Flow Hedges:
		Commodity Hedges (b)		-			84			-			-			84
	Total Risk Management Assets		$	-		$	1,162		$	-		$	5		$	1,167

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	81		$	-		$	4		$	85
	(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
	(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
	(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
	(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
	(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

	Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
	Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
	Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			3,289			2,052			4,065			349			442
	Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
	Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				257			179			366			-			-
	Transfers into Level 3 (d) (e)				632			434			888			-			-
	Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			-1,123			-732			490			-			-
	Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
(a) Included in revenues on the condensed statements of income.
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c) Represents the settlement of risk management commodity contracts for the reporting period.
(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) Represents existing assets or liabilities that were previously categorized as Level 3.
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of March 31, 2014 and December 31, 2013:
	Significant Unobservable Inputs
	31-Mar-14
	PSO
			Fair Value						Valuation		Significant		Forward Price Range
			Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
			(in thousands)
	Energy Contracts		$	-		$	-		Discounted Cash Flow		Forward Market Price		$	-		$	-
	FTRs			481			132		Discounted Cash Flow		Forward Market Price			-5.05			9.17
	Total		$	481		$	132
(a) Represents market prices in dollars per MWh.
Southwestern Electric Power Co [Member]	'
Fair Value Measurements	'
	9. FAIR VALUE MEASUREMENTS

	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

	The book values and fair values of Long-term Debt for the Registrant Subsidiaries as of March 31, 2014 and December 31, 2013 are summarized in the following table:
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
	Fair Value Measurements of Financial Assets and Liabilities

	The following tables set forth, by level within the fair value hierarchy, the Registrant Subsidiaries' financial assets and liabilities that were accounted for at fair value on a recurring basis as of March 31, 2014 and December 31, 2013. 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.

	SWEPCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Cash and Cash Equivalents (a)		$	15,537		$	-		$	-		$	2,458		$	17,995

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			-			1,471			609			-173			1,907

	Total Assets		$	15,537		$	1,471		$	609		$	2,285		$	19,902

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	4		$	167		$	-171		$	-
	SWEPCo
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Cash and Cash Equivalents (a)		$	15,871		$	-		$	-		$	1,370		$	17,241

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			-			1,233			-			-151			1,082
	Cash Flow Hedges:
		Commodity Hedges (b)		-			97			-			-			97
	Total Risk Management Assets			-			1,330			-			-151			1,179

	Total Assets		$	15,871		$	1,330		$	-		$	1,219		$	18,420

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (b) (c)		$	-		$	154		$	-		$	-154		$	-
(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
There were no transfers between Level 1 and Level 2 during the three months ended March 31, 2014 and 2013.

The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy:

	Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
	Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
	Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			3,289			2,052			4,065			349			442
	Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
	Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
				(in thousands)
	Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
	Realized Gain (Loss) Included in Net Income
		(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
	Unrealized Gain (Loss) Included in Net
		Income (or Changes in Net Assets) Relating
		to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
	Realized and Unrealized Gains (Losses)
		Included in Other Comprehensive Income			-			-			-			-			-
	Purchases, Issuances and Settlements (c)				257			179			366			-			-
	Transfers into Level 3 (d) (e)				632			434			888			-			-
	Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
	Changes in Fair Value Allocated to Regulated
		Jurisdictions (g)			-1,123			-732			490			-			-
	Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
(a) Included in revenues on the condensed statements of income.
(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
(c) Represents the settlement of risk management commodity contracts for the reporting period.
(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) Represents existing assets or liabilities that were previously categorized as Level 3.
(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
The following tables quantify the significant unobservable inputs used in developing the fair value of Level 3 positions as of March 31, 2014 and December 31, 2013:
	Significant Unobservable Inputs
	31-Mar-14
	SWEPCo
			Fair Value						Valuation		Significant		Forward Price Range
			Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
			(in thousands)
	Energy Contracts		$	-		$	-		Discounted Cash Flow		Forward Market Price		$	-		$	-
	FTRs			609			167		Discounted Cash Flow		Forward Market Price			-5.05			9.17
	Total		$	609		$	167
(a) Represents market prices in dollars per MWh.

Income_Taxes

Income Taxes	3 Months Ended
Income Taxes	Mar. 31, 2014
Income Taxes	'
	AEP System Tax Allocation Agreement

	We, along with our subsidiaries, file a consolidated federal income tax return. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

	Federal and State Income Tax Audit Status

	The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The IRS examination of years 2011 and 2012 started in April 2014. Although the outcome of tax audits is uncertain, in our opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, we accrue interest on these uncertain tax positions. We are not aware of any issues for open tax years that upon final resolution are expected to materially impact net income.

	We, along with our subsidiaries, file income tax returns in various state, local and foreign jurisdictions. These taxing authorities routinely examine our tax returns. We are currently under examination in several state and local jurisdictions. However, it is possible that we have filed tax returns with positions that may be challenged by these tax authorities. We believe 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. We are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2009.
Appalachian Power Co [Member]	'
Income Taxes	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

	Federal and State Income Tax Audit Status

	The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The IRS examination of years 2011 and 2012 started in April 2014. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries 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.

	The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant 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 Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009.
Indiana Michigan Power Co [Member]	'
Income Taxes	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

	Federal and State Income Tax Audit Status

	The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The IRS examination of years 2011 and 2012 started in April 2014. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries 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.

	The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant 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 Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009.
Ohio Power Co [Member]	'
Income Taxes	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

	Federal and State Income Tax Audit Status

	The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The IRS examination of years 2011 and 2012 started in April 2014. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries 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.

	The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant 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 Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009.
Public Service Co Of Oklahoma [Member]	'
Income Taxes	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

	Federal and State Income Tax Audit Status

	The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The IRS examination of years 2011 and 2012 started in April 2014. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries 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.

	The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant 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 Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009.
Southwestern Electric Power Co [Member]	'
Income Taxes	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

	Federal and State Income Tax Audit Status

	The IRS examination of years 2009 and 2010 started in October 2011 and was completed in the second quarter of 2013. The IRS examination of years 2011 and 2012 started in April 2014. Although the outcome of tax audits is uncertain, in management's opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the Registrant Subsidiaries 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.

	The Registrant Subsidiaries file income tax returns in various state and local jurisdictions. These taxing authorities routinely examine the tax returns and the Registrant 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 Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009.

Financing_Activities

Financing Activities	3 Months Ended
Financing Activities	Mar. 31, 2014
Financing Activities	'
	11. FINANCING ACTIVITIES

	Long-term Debt

	The following table details long-term debt outstanding as of March 31, 2014 and December 31, 2013:
		Type of Debt		31-Mar-14			31-Dec-13
				(in millions)
		Senior Unsecured Notes		$	11,571		$	11,799
		Pollution Control Bonds			1,932			1,932
		Notes Payable			342			369
		Securitization Bonds			2,574			2,686
		Spent Nuclear Fuel Obligation (a)			265			265
		Other Long-term Debt			1,434			1,360
		Fair Value of Interest Rate Hedges			-7			-9
		Unamortized Discount, Net			-24			-25
		Total Long-term Debt Outstanding			18,087			18,377
		Long-term Debt Due Within One Year			1,612			1,549
		Long-term Debt		$	16,475		$	16,828
	(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of March 31, 2014 and December 31, 2013, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

	Long-term debt and other securities issued, retired and principal payments made during the first three months of 2014 are shown in the tables below:
							Principal				Interest
		Company			Type of Debt		Amount				Rate		Due Date
		Issuances:				(in millions)					(%)
		PSO			Other Long-term Debt		$	50			Variable		2016

		Non-Registrant:
		Transource Missouri			Other Long-term Debt			27			Variable		2018
		Total Issuances					$	77	(a)
							Principal				Interest
		Company			Type of Debt		Amount Paid				Rate		Due Date
		Retirements and				(in millions)					(%)
			Principal Payments:
		I&M			Notes Payable		$	5			Variable		2016
		I&M			Notes Payable			4			2.12		2016
		I&M			Notes Payable			5			Variable		2016
		I&M			Notes Payable			10			Variable		2017
		I&M			Other Long-term Debt			2			Variable		2015
		OPCo			Senior Unsecured Notes			225			4.85		2014
		SWEPCo			Notes Payable			2			4.58		2032

		Non-Registrant:
		AEGCo			Senior Unsecured Notes			4			6.33		2037
		AEP Subsidiaries			Notes Payable			1			Variable		2017
		TCC			Securitization Bonds			72			5.09		2015
		TCC			Securitization Bonds			40			6.25		2016
		Total Retirements and
			Principal Payments				$	370
	(a) Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances.

	In April 2014, I&M retired $13 million of Notes Payable related to DCC Fuel.

	As of March 31, 2014, trustees held on our behalf, $500 million of our reacquired Pollution Control Bonds.
	Dividend Restrictions

	Parent Restrictions

	The holders of our common stock are entitled to receive the dividends declared by our Board of Directors provided funds are legally available for such dividends. Our income primarily derives from our common stock equity in the earnings of our utility subsidiaries.

	Pursuant to the leverage restrictions in our credit agreements, we 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. None of AEP's retained earnings were restricted for the purpose of the payment of dividends.

	Utility Subsidiaries' Restrictions

Various financing arrangements and regulatory requirements may impose certain restrictions on the ability of our utility subsidiaries to transfer funds to us in the form of dividends. Specifically, several of our public utility subsidiaries have credit agreements that contain a covenant that limits their debt to capitalization ratio to 67.5%.

The Federal Power Act prohibits the utility subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock. This restriction does not limit the ability of the utility subsidiaries to pay dividends out of retained earnings.
Short-term Debt

Our outstanding short-term debt was as follows:
				31-Mar-14						31-Dec-13
				Outstanding			Interest			Outstanding			Interest
	Type of Debt			Amount			Rate (a)			Amount			Rate (a)
				(in millions)						(in millions)
	Securitized Debt for Receivables (b)			$	700		0.24	%		$	700		0.23	%
	Commercial Paper				632		0.31	%			57		0.29	%
	Total Short-term Debt			$	1,332					$	757
(a) Weighted average rate.
(b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.

Credit Facilities

For an additional discussion of credit facilities, see “Letters of Credit” section of Note 5.
Securitized Accounts Receivable – AEP Credit

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. AEP Credit continues to service the receivables. These securitized transactions allow AEP Credit to repay its outstanding debt obligations, continue to purchase our operating companies' receivables and accelerate AEP Credit's cash collections.

Our receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. We intend to extend or replace the agreement expiring in June 2014 on or before its maturity.

Accounts receivable information for AEP Credit is as follows:
				Three Months Ended
				March 31,
				2014			2013
				(dollars in millions)
	Effective Interest Rates on Securitization of Accounts Receivable				0.24	%		0.23	%
	Net Uncollectible Accounts Receivable Written Off			$	8		$	7
				March 31,			December 31,
				2014			2013
				(in millions)
	Accounts Receivable Retained Interest and Pledged as Collateral
		Less Uncollectible Accounts		$	997		$	929
	Total Principal Outstanding				700			700
	Delinquent Securitized Accounts Receivable				55			45
	Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable				17			16
	Unbilled Receivables Related to Securitization/Sale of Accounts Receivable				278			331
Customer accounts receivable retained and securitized for our operating companies are managed by AEP Credit. AEP Credit's delinquent customer accounts receivable represents accounts greater than 30 days past due.

Appalachian Power Co [Member]	'
Financing Activities	'
	11. FINANCING ACTIVITIES

	Long-term Debt

	Long-term debt and other securities issued, retired and principal payments made during the first three months of 2014 are shown in the tables below:
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

	Dividend Restrictions

	The Registrant 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 Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

	Federal Power Act

	The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock.

	Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

	None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

	Leverage Restrictions

	Pursuant to the credit agreement leverage restrictions, APCo, I&M and PSO must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.
	Utility Money Pool – AEP System

	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 a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2014 and December 31, 2013 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2014 are described in the following table:
															Net
															Loans to
				Maximum			Maximum			Average			Average		(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans		the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility		Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool		31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681	$	245,516	$	600,000
		I&M			-			158,857			-			92,303		59,162		500,000
		OPCo			55,640			405,350			25,930			135,747		-27,108		600,000
		PSO			121,100			-			58,500			-		-70,119		300,000
		SWEPCo			130,258			-			61,132			-		-117,342		350,000
	The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
	The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table:
				Average Interest Rate						Average Interest Rate
			for Funds Borrowed						for Funds Loaned
			from the Utility Money Pool for						to the Utility Money Pool for
			Three Months Ended March 31,						Three Months Ended March 31,
	Company		2014			2013			2014			2013
	APCo		-	%		0.38	%		0.31	%		0.37	%
	I&M		-	%		0.36	%		0.31	%		0.37	%
	OPCo		0.31	%		0.36	%		0.29	%		0.37	%
	PSO		0.31	%		0.36	%		-	%		0.38	%
	SWEPCo		0.31	%		-	%		-	%		0.38	%
Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.
Sale of Receivables – AEP Credit

Under a 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' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows:
				March 31,			December 31,
	Company			2014			2013
				(in thousands)
	APCo			$	175,738		$	156,599
	I&M				154,510			139,257
	OPCo				350,735			324,287
	PSO				111,522			115,260
	SWEPCo				145,648			149,337
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	2,423		$	1,556
	I&M				2,040			1,452
	OPCo				7,498			4,669
	PSO				1,323			1,414
	SWEPCo				1,566			1,380
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	437,196		$	398,193
	I&M				407,150			351,830
	OPCo				686,627			696,958
	PSO				290,217			240,275
	SWEPCo				390,588			331,936
Indiana Michigan Power Co [Member]	'
Financing Activities	'
	11. FINANCING ACTIVITIES

	Long-term Debt

	Long-term debt and other securities issued, retired and principal payments made during the first three months of 2014 are shown in the tables below:
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
	In April 2014, I&M retired $13 million of Notes Payable related to DCC Fuel.

	As of March 31, 2014, trustees held on behalf of I&M and OPCo, $40 million and $460 million, respectively, of their reacquired Pollution Control Bonds.

	Dividend Restrictions

	The Registrant 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 Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

	Federal Power Act

	The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock.

	Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

	None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

	Leverage Restrictions

	Pursuant to the credit agreement leverage restrictions, APCo, I&M and PSO must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.
	Utility Money Pool – AEP System

	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 a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2014 and December 31, 2013 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2014 are described in the following table:
															Net
															Loans to
				Maximum			Maximum			Average			Average		(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans		the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility		Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool		31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681	$	245,516	$	600,000
		I&M			-			158,857			-			92,303		59,162		500,000
		OPCo			55,640			405,350			25,930			135,747		-27,108		600,000
		PSO			121,100			-			58,500			-		-70,119		300,000
		SWEPCo			130,258			-			61,132			-		-117,342		350,000
	The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
	Minimum Interest Rate		0.28	%		0.35	%
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table:
			Average Interest Rate						Average Interest Rate
			for Funds Borrowed						for Funds Loaned
			from the Utility Money Pool for						to the Utility Money Pool for
			Three Months Ended March 31,						Three Months Ended March 31,
	Company		2014			2013			2014			2013
	APCo		-	%		0.38	%		0.31	%		0.37	%
	I&M		-	%		0.36	%		0.31	%		0.37	%
	OPCo		0.31	%		0.36	%		0.29	%		0.37	%
	PSO		0.31	%		0.36	%		-	%		0.38	%
	SWEPCo		0.31	%		-	%		-	%		0.38	%
Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.
Sale of Receivables – AEP Credit

Under a 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' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows:
				March 31,			December 31,
	Company			2014			2013
				(in thousands)
	APCo			$	175,738		$	156,599
	I&M				154,510			139,257
	OPCo				350,735			324,287
	PSO				111,522			115,260
	SWEPCo				145,648			149,337
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	2,423		$	1,556
	I&M				2,040			1,452
	OPCo				7,498			4,669
	PSO				1,323			1,414
	SWEPCo				1,566			1,380
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	437,196		$	398,193
	I&M				407,150			351,830
	OPCo				686,627			696,958
	PSO				290,217			240,275
	SWEPCo				390,588			331,936
Ohio Power Co [Member]	'
Financing Activities	'
	11. FINANCING ACTIVITIES

	Long-term Debt

	Long-term debt and other securities issued, retired and principal payments made during the first three months of 2014 are shown in the tables below:
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

	As of March 31, 2014, trustees held on behalf of I&M and OPCo, $40 million and $460 million, respectively, of their reacquired Pollution Control Bonds.

	Dividend Restrictions

	The Registrant 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 Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

	Federal Power Act

	The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock.

	Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

	None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

	Leverage Restrictions

	Pursuant to the credit agreement leverage restrictions, APCo, I&M and PSO must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.
	Utility Money Pool – AEP System

	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 a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2014 and December 31, 2013 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2014 are described in the following table:
															Net
															Loans to
				Maximum			Maximum			Average			Average		(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans		the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility		Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool		31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681	$	245,516	$	600,000
		I&M			-			158,857			-			92,303		59,162		500,000
		OPCo			55,640			405,350			25,930			135,747		-27,108		600,000
		PSO			121,100			-			58,500			-		-70,119		300,000
		SWEPCo			130,258			-			61,132			-		-117,342		350,000
	The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table:
			Average Interest Rate						Average Interest Rate
			for Funds Borrowed						for Funds Loaned
			from the Utility Money Pool for						to the Utility Money Pool for
			Three Months Ended March 31,						Three Months Ended March 31,
	Company		2014			2013			2014			2013
	APCo		-	%		0.38	%		0.31	%		0.37	%
	I&M		-	%		0.36	%		0.31	%		0.37	%
	OPCo		0.31	%		0.36	%		0.29	%		0.37	%
	PSO		0.31	%		0.36	%		-	%		0.38	%
	SWEPCo		0.31	%		-	%		-	%		0.38	%
Credit Facilities

For a discussion of credit facilities, see “Letters of Credit” section of Note 5.
Sale of Receivables – AEP Credit

Under a 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' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows:
				March 31,			December 31,
	Company			2014			2013
				(in thousands)
	APCo			$	175,738		$	156,599
	I&M				154,510			139,257
	OPCo				350,735			324,287
	PSO				111,522			115,260
	SWEPCo				145,648			149,337
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	2,423		$	1,556
	I&M				2,040			1,452
	OPCo				7,498			4,669
	PSO				1,323			1,414
	SWEPCo				1,566			1,380
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	437,196		$	398,193
	I&M				407,150			351,830
	OPCo				686,627			696,958
	PSO				290,217			240,275
	SWEPCo				390,588			331,936
Public Service Co Of Oklahoma [Member]	'
Financing Activities	'
	11. FINANCING ACTIVITIES

	Long-term Debt

	Long-term debt and other securities issued, retired and principal payments made during the first three months of 2014 are shown in the tables below:
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

	Dividend Restrictions

	The Registrant 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 Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

	Federal Power Act

	The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock.

	Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

	None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

	Leverage Restrictions

	Pursuant to the credit agreement leverage restrictions, APCo, I&M and PSO must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.
	Utility Money Pool – AEP System

	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 a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2014 and December 31, 2013 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2014 are described in the following table:
															Net
															Loans to
				Maximum			Maximum			Average			Average		(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans		the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility		Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool		31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681	$	245,516	$	600,000
		I&M			-			158,857			-			92,303		59,162		500,000
		OPCo			55,640			405,350			25,930			135,747		-27,108		600,000
		PSO			121,100			-			58,500			-		-70,119		300,000
		SWEPCo			130,258			-			61,132			-		-117,342		350,000
	The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
	The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table:
				Average Interest Rate						Average Interest Rate
			for Funds Borrowed						for Funds Loaned
			from the Utility Money Pool for						to the Utility Money Pool for
			Three Months Ended March 31,						Three Months Ended March 31,
	Company		2014			2013			2014			2013
	APCo		-	%		0.38	%		0.31	%		0.37	%
	I&M		-	%		0.36	%		0.31	%		0.37	%
	OPCo		0.31	%		0.36	%		0.29	%		0.37	%
	PSO		0.31	%		0.36	%		-	%		0.38	%
	SWEPCo		0.31	%		-	%		-	%		0.38	%
Sale of Receivables – AEP Credit

Under a 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' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows:
				March 31,			December 31,
	Company			2014			2013
				(in thousands)
	APCo			$	175,738		$	156,599
	I&M				154,510			139,257
	OPCo				350,735			324,287
	PSO				111,522			115,260
	SWEPCo				145,648			149,337
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	2,423		$	1,556
	I&M				2,040			1,452
	OPCo				7,498			4,669
	PSO				1,323			1,414
	SWEPCo				1,566			1,380
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	437,196		$	398,193
	I&M				407,150			351,830
	OPCo				686,627			696,958
	PSO				290,217			240,275
	SWEPCo				390,588			331,936
Southwestern Electric Power Co [Member]	'
Financing Activities	'
	11. FINANCING ACTIVITIES

	Long-term Debt

	Long-term debt and other securities issued, retired and principal payments made during the first three months of 2014 are shown in the tables below:
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

	Dividend Restrictions

	The Registrant 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 Registrant Subsidiaries to transfer funds to Parent in the form of dividends.

	Federal Power Act

	The Federal Power Act prohibits each of the Registrant Subsidiaries from participating “in the making or paying of any dividends of such public utility from any funds properly included in capital account.” The term “capital account” is not defined in the Federal Power Act or its regulations. Management understands “capital account” to mean the book value of the common stock.

	Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M.

	None of these restrictions limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings.

	Leverage Restrictions

	Pursuant to the credit agreement leverage restrictions, APCo, I&M and PSO must maintain a percentage of debt to total capitalization at a level that does not exceed 67.5%.
	Utility Money Pool – AEP System

	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 a majority of AEP's nonutility subsidiaries. The AEP System Utility Money Pool operates in accordance with the terms and conditions of the AEP System Utility Money Pool agreement filed with the FERC. The amounts of outstanding loans to (borrowings from) the Utility Money Pool as of March 31, 2014 and December 31, 2013 are included in Advances to Affiliates and Advances from Affiliates, respectively, on each of the Registrant Subsidiaries' condensed balance sheets. The Utility Money Pool participants' money pool activity and their corresponding authorized borrowing limits for the three months ended March 31, 2014 are described in the following table:
															Net
															Loans to
				Maximum			Maximum			Average			Average		(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans		the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility		Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool		31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681	$	245,516	$	600,000
		I&M			-			158,857			-			92,303		59,162		500,000
		OPCo			55,640			405,350			25,930			135,747		-27,108		600,000
		PSO			121,100			-			58,500			-		-70,119		300,000
		SWEPCo			130,258			-			61,132			-		-117,342		350,000
	The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows:
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
	The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the three months ended March 31, 2014 and 2013 are summarized for all Registrant Subsidiaries in the following table:
				Average Interest Rate						Average Interest Rate
			for Funds Borrowed						for Funds Loaned
			from the Utility Money Pool for						to the Utility Money Pool for
			Three Months Ended March 31,						Three Months Ended March 31,
	Company		2014			2013			2014			2013
	APCo		-	%		0.38	%		0.31	%		0.37	%
	I&M		-	%		0.36	%		0.31	%		0.37	%
	OPCo		0.31	%		0.36	%		0.29	%		0.37	%
	PSO		0.31	%		0.36	%		-	%		0.38	%
	SWEPCo		0.31	%		-	%		-	%		0.38	%
Sale of Receivables – AEP Credit

Under a 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' condensed statements of income. The Registrant Subsidiaries manage and service their customer accounts receivable sold.

AEP Credit's receivables securitization agreement provides a commitment of $700 million from bank conduits to purchase receivables. A commitment of $385 million expires in June 2014. The remaining commitment of $315 million expires in June 2015. AEP Credit intends to extend or replace the agreement expiring in June 2014 on or before its maturity.

The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of March 31, 2014 and December 31, 2013 was as follows:
				March 31,			December 31,
	Company			2014			2013
				(in thousands)
	APCo			$	175,738		$	156,599
	I&M				154,510			139,257
	OPCo				350,735			324,287
	PSO				111,522			115,260
	SWEPCo				145,648			149,337
The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	2,423		$	1,556
	I&M				2,040			1,452
	OPCo				7,498			4,669
	PSO				1,323			1,414
	SWEPCo				1,566			1,380
The Registrant Subsidiaries' proceeds on the sale of receivables to AEP Credit were:
				Three Months Ended March 31,
	Company			2014			2013
				(in thousands)
	APCo			$	437,196		$	398,193
	I&M				407,150			351,830
	OPCo				686,627			696,958
	PSO				290,217			240,275
	SWEPCo				390,588			331,936

Variable_Interest_Entities

Variable Interest Entities	3 Months Ended
Variable Interest Entities	Mar. 31, 2014
Variable Interest Entities	'
	12. VARIABLE INTEREST ENTITIES

	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE's variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. We believe that significant assumptions and judgments were applied consistently.

	We are the primary beneficiary of Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, a protected cell of EIS and Transource Energy. In addition, we have not provided material financial or other support to Sabine, DCC Fuel, AEP Credit, Transition Funding, Ohio Phase-in-Recovery Funding, Appalachian Consumer Rate Relief Funding, our protected cell of EIS and Transource Energy that was not previously contractually required. We hold a significant variable interest in DHLC and Potomac-Appalachian Transmission Highline, LLC West Virginia Series (West Virginia Series).

	Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine's only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo's total billings from Sabine for the three months ended March 31, 2014 and 2013 were $39 million and $44 million, respectively. See the tables below for the classification of Sabine's assets and liabilities on the condensed balance sheets.

	I&M has nuclear fuel lease agreements with DCC Fuel II LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel). DCC Fuel 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 entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended March 31, 2014 and 2013 were $25 million and $26 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 our 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. In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC. See the tables below for the classification of DCC Fuel's assets and liabilities on the condensed balance sheets.

	AEP Credit is a wholly-owned subsidiary of AEP. 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 our control of AEP Credit, management concluded that we are the primary beneficiary and are required to consolidate AEP Credit. See the tables below for the classification of AEP Credit's assets and liabilities on the condensed balance sheets. See “Securitized Accounts Receivables – AEP Credit” section of Note 11.

	Transition Funding was formed for the sole purpose of issuing and servicing securitization bonds related to Texas Restructuring Legislation. Management has concluded that TCC is the primary beneficiary of Transition Funding because TCC has the power to direct the most significant activities of the VIE and TCC's equity interest could potentially be significant. Therefore, TCC is required to consolidate Transition Funding. The securitized bonds totaled $2 billion and $2 billion as of March 31, 2014 and December 31, 2013, respectively. Transition Funding has securitized transition assets of $1.8 billion and $1.9 billion as of March 31, 2014 and December 31, 2013, respectively. The securitized transition assets represent the right to impose and collect Texas true-up costs from customers receiving electric transmission or distribution service from TCC under recovery mechanisms approved by the PUCT. The securitization bonds are payable only from and secured by the securitized transition assets. The bondholders have no recourse to TCC or any other AEP entity. TCC acts as the servicer for Transition Funding's securitized transition assets and remits all related amounts collected from customers to Transition Funding for interest and principal payments on the securitization bonds and related costs. See the tables below for the classification of Transition Funding's assets and liabilities on the condensed 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 $267 million and $267 million as of March 31, 2014 and December 31, 2013, respectively. Ohio Phase-in-Recovery Funding has securitized assets of $127 million and $132 million as of March 31, 2014 and December 31, 2013, respectively. The phase-in recovery property represents the right to impose and collect Ohio deferred distribution charges from customers receiving electric transmission and distribution service from OPCo under a recovery mechanism approved by the PUCO. In August 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to OPCo or any other AEP entity. OPCo acts as the servicer for Ohio Phase-in-Recovery Funding's securitized assets and remits all related amounts collected from customers to Ohio Phase-in-Recovery Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Ohio Phase-in-Recovery Funding's assets and liabilities on the condensed 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 $380 million and $380 million as of March 31, 2014 and December 31, 2013, respectively. Appalachian Consumer Rate Relief Funding has securitized assets of $365 million and $369 million as of March 31, 2014 and December 31, 2013, respectively. The phase-in recovery property represents the right to impose and collect West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding's assets and liabilities on the condensed balance sheets.

	The securitized bonds of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in current and long-term debt on the condensed balance sheets. The securitized assets of Transition Funding, Ohio Phase-in-Recovery Funding and Appalachian Consumer Rate Relief Funding are included in securitized assets on the condensed balance sheets.

	Our subsidiaries participate in one protected cell of EIS for approximately ten lines of insurance. EIS has multiple protected cells. Neither AEP nor its subsidiaries have an equity investment in EIS. The AEP System is essentially this EIS cell's only participant, but allows certain third parties access to this insurance. Our subsidiaries and any allowed third parties share in the insurance coverage, premiums and risk of loss from claims. Based on our control and the structure of the protected cell and EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate EIS. Our insurance premium expense to the protected cell for the three months ended March 31, 2014 and 2013 was $16 million and $15 million, respectively. See the tables below for the classification of the protected cell's assets and liabilities on the condensed 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. AEP's equity interest could potentially be significant. Therefore, AEP is required to consolidate Transource Energy. In January 2014, Transource Missouri acquired transmission assets from the non-controlling owner and issued debt and received capital contributions to fund the acquisition. The majority of Transource Energy's activity resulted from the asset acquisition, debt issuance and capital contribution. See the table below for the classification of Transource Energy's assets and liabilities on the condensed 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
	31-Mar-14
	(in millions)

																			APCo
																OPCo			Appalachian
																Ohio			Consumer
													TCC			Phase-in-			Rate			Protected
				SWEPCo			I&M			AEP			Transition			Recovery			Relief			Cell		Transource
				Sabine			DCC Fuel			Credit			Funding			Funding			Funding			of EIS		Energy
	ASSETS
	Current Assets			$	62		$	109		$	1,004		$	166		$	36		$	16		$	152	$	4
	Net Property, Plant and
		Equipment			154			129			-			-			-			-			-		57
	Other Noncurrent Assets				50			45			-			1,861	(a)		242	(b)		374	(c)		3		5
	Total Assets			$	266		$	283		$	1,004		$	2,027		$	278		$	390		$	155	$	66

	LIABILITIES AND EQUITY
	Current Liabilities			$	29		$	100		$	894		$	304		$	60		$	28		$	48	$	18
	Noncurrent Liabilities				236			183			1			1,705			217			360			67		28
	Equity				1			-			109			18			1			2			40		20
	Total Liabilities and Equity			$	266		$	283		$	1,004		$	2,027		$	278		$	390		$	155	$	66
	(a) Includes an intercompany item eliminated in consolidation of $81 million.
	(b) Includes an intercompany item eliminated in consolidation of $112 million.
	(c) Includes an intercompany item eliminated in consolidation of $4 million.
	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
	VARIABLE INTEREST ENTITIES
	31-Dec-13
	(in millions)

																		APCo
															OPCo			Appalachian
															Ohio			Consumer
												TCC			Phase-in-			Rate
			SWEPCo			I&M			AEP			Transition			Recovery			Relief			Protected Cell
			Sabine			DCC Fuel			Credit			Funding			Funding			Funding			of EIS
	ASSETS
Current Assets		$	67		$	118		$	935		$	232		$	23		$	6		$	143
Net Property, Plant and Equipment			157			157			-			-			-			-			-
Other Noncurrent Assets			51			60			1			1,918	(a)		252	(b)		378	(c)		3
Total Assets		$	275		$	335		$	936		$	2,150		$	275		$	384		$	146

LIABILITIES AND EQUITY
Current Liabilities		$	33		$	108		$	827		$	312		$	37		$	14		$	39
Noncurrent Liabilities			242			227			1			1,820			237			368			66
Equity			-			-			108			18			1			2			41
Total Liabilities and Equity		$	275		$	335		$	936		$	2,150		$	275		$	384		$	146
(a) Includes an intercompany item eliminated in consolidation of $82 million.
(b) Includes an intercompany item eliminated in consolidation of $116 million.
(c) Includes an intercompany item eliminated in consolidation of $4 million.

DHLC is a mining operator that sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC's debt. SWEPCo and CLECO equally approve DHLC's annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo's total billings from DHLC for the three months ended March 31, 2014 and 2013 were $2 million and $18 million, respectively. We are not required to consolidate DHLC as we are not the primary beneficiary, although we hold a significant variable interest in DHLC. Our equity investment in DHLC is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets.

Our investment in DHLC was:
			31-Mar-14						31-Dec-13
			As Reported on			Maximum			As Reported on			Maximum
			the Balance Sheet			Exposure			the Balance Sheet			Exposure
			(in millions)
	Capital Contribution from SWEPCo		$	8		$	8		$	8		$	8
	Retained Earnings			2			2			1			1
	SWEPCo's Guarantee of Debt			-			85			-			61

	Total Investment in DHLC		$	10		$	95		$	9		$	70
We 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. The “Allegheny Series” is not considered a VIE. We are not required to consolidate PATH-WV as we are not the primary beneficiary, although we hold a significant variable interest in PATH-WV. Our equity investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on our condensed balance sheets. We and FirstEnergy share the returns and losses equally in PATH-WV. Our 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, our transmission joint venture with FirstEnergy, and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project's abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement. In March 2014, the settlement judge recommended termination of the settlement proceedings and this case is expected to proceed to a hearing.

Our investment in PATH-WV was:
		31-Mar-14						31-Dec-13
		As Reported on			Maximum			As Reported on			Maximum
		the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in millions)
	Capital Contribution from AEP	$	19		$	19		$	19		$	19
	Retained Earnings		6			6			6			6

	Total Investment in PATH-WV	$	25		$	25		$	25		$	25
As of March 31, 2014, our $25 million investment in PATH-WV is included in Deferred Charges and Other Noncurrent Assets on the condensed balance sheet. If we cannot ultimately recover our investment related to PATH-WV, it could reduce future net income and cash flows.
Appalachian Power Co [Member]	'
Variable Interest Entities	'
	12. VARIABLE INTEREST ENTITIES
	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

	SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo.
	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 $380 million and $380 million as of March 31, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $365 million and $369 as of March 31, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed balance sheets. The phase-in recovery property represents the right to impose and collect WV 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.

	The balances below represent the assets and liabilities of Appalachian Consumer Rate Relief Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
		APPALACHIAN POWER COMPANY AND SUBSIDIARIES
		VARIABLE INTEREST ENTITIES
		March 31, 2014 and December 31, 2013
		(in thousands)
				Appalachian Consumer
				Rate Relief Funding
		ASSETS		2014			2013
		Current Assets		$	15,981		$	5,891
		Other Noncurrent Assets (a)			373,521			378,029
		Total Assets		$	389,502		$	383,920

		LIABILITIES AND EQUITY
		Current Liabilities		$	27,682		$	14,000
		Noncurrent Liabilities			359,919			368,018
		Equity			1,901			1,902
		Total Liabilities and Equity		$	389,502		$	383,920
	(a) Includes an intercompany item eliminated in consolidation as of March 31, 2014 of and December 31, 2013 of $4 million and $4 million, respectively.
	AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

	Total AEPSC billings to the Registrant Subsidiaries were as follows:

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
	The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
Indiana Michigan Power Co [Member]	'
Variable Interest Entities	'
	12. VARIABLE INTEREST ENTITIES
	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

	SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo.
	I&M has nuclear fuel lease agreements with DCC Fuel II LLC, DCC Fuel IV LLC, DCC Fuel V LLC and DCC Fuel VI LLC (collectively DCC Fuel). DCC Fuel 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 entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended March 31, 2014 and 2013 were $25 million and $26 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. In October 2013, the lease agreements ended for DCC Fuel LLC and DCC Fuel III LLC. See the table below for the classification of DCC Fuel's assets and liabilities on I&M's condensed balance sheets.

	The balances below represent the assets and liabilities of DCC Fuel that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
		INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
		VARIABLE INTEREST ENTITIES
		March 31, 2014 and December 31, 2013
		(in thousands)
				DCC Fuel
		ASSETS		2014			2013
		Current Assets		$	109,374		$	117,762
		Net Property, Plant and Equipment			129,013			156,820
		Other Noncurrent Assets			44,853			60,450
		Total Assets		$	283,240		$	335,032

		LIABILITIES AND EQUITY
		Current Liabilities		$	100,141		$	107,815
		Noncurrent Liabilities			183,099			227,217
		Total Liabilities and Equity		$	283,240		$	335,032
	AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

	Total AEPSC billings to the Registrant Subsidiaries were as follows:

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
	The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
	AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo's lease, see “Rockport Lease” section of Note 12 in the 2013 Annual Report.

	Total billings from AEGCo were as follows:

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		I&M		$	70,422		$	58,535
		OPCo			-			38,711
	The carrying amount and classification of variable interest in AEGCo's accounts payable are as follows:
				31-Mar-14						31-Dec-13
				As Reported on			Maximum			As Reported on			Maximum
		Company		the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in thousands)
		I&M		$	24,364		$	24,364		$	23,916		$	23,916
		OPCo			-			-			12,810			12,810
Ohio Power Co [Member]	'
Variable Interest Entities	'
	12. VARIABLE INTEREST ENTITIES
	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

	SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo.
	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 $267 million and $267 million as of March 31, 2014 and December 31, 2013, respectively, and are included in current and long-term debt on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $127 million and $132 million as of March 31, 2014 and December 31, 2013, respectively, which are presented separately on the face of the condensed 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.

	The balances below represent the assets and liabilities of Ohio Phase-in-Recovery Funding that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
		OHIO POWER COMPANY AND SUBSIDIARIES
		VARIABLE INTEREST ENTITIES
		March 31, 2014 and December 31, 2013
		(in thousands)
				Ohio Phase-in-
				Recovery Funding
		ASSETS		2014			2013
		Current Assets		$	35,958		$	23,198
		Other Noncurrent Assets (a)			241,814			251,409
		Total Assets		$	277,772		$	274,607

		LIABILITIES AND EQUITY
		Current Liabilities		$	59,590		$	36,470
		Noncurrent Liabilities			216,845			236,800
		Equity			1,337			1,337
		Total Liabilities and Equity		$	277,772		$	274,607
	(a) Includes an intercompany item eliminated in consolidation as of March 31, 2014 and December 31, 2013 of $112 million and $116 million, respectively.
	AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

	Total AEPSC billings to the Registrant Subsidiaries were as follows:

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
	The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
	AEGCo, a wholly-owned subsidiary of AEP, is consolidated by AEP. AEGCo owns a 50% ownership interest in Rockport Plant, Unit 1, leases a 50% interest in Rockport Plant, Unit 2 and owns 100% of the Lawrenceburg Generating Station. AEGCo sells all the output from the Rockport Plant to I&M and KPCo. AEGCo has a Unit Power Agreement associated with the Lawrenceburg Generating Station which was assigned by OPCo to AGR effective January 1, 2014. AEP has agreed to provide AEGCo with the funds necessary to satisfy all of the debt obligations of AEGCo. I&M is considered to have a significant interest in AEGCo due to these transactions. I&M is exposed to losses to the extent it cannot recover the costs of AEGCo through its normal business operations. In the event AEGCo would require financing or other support outside the billings to I&M and KPCo, this financing would be provided by AEP. For additional information regarding AEGCo's lease, see “Rockport Lease” section of Note 12 in the 2013 Annual Report.

	Total billings from AEGCo were as follows:

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		I&M		$	70,422		$	58,535
		OPCo			-			38,711
	The carrying amount and classification of variable interest in AEGCo's accounts payable are as follows:
				31-Mar-14						31-Dec-13
				As Reported on			Maximum			As Reported on			Maximum
		Company		the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in thousands)
		I&M		$	24,364		$	24,364		$	23,916		$	23,916
		OPCo			-			-			12,810			12,810
Public Service Co Of Oklahoma [Member]	'
Variable Interest Entities	'
	12. VARIABLE INTEREST ENTITIES
	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

	SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo.
	AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

	Total AEPSC billings to the Registrant Subsidiaries were as follows:

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
	The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
Southwestern Electric Power Co [Member]	'
Variable Interest Entities	'
	12. VARIABLE INTEREST ENTITIES
	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

	SWEPCo is the primary beneficiary of Sabine. I&M is the primary beneficiary of DCC Fuel. OPCo is the primary beneficiary of Ohio Phase-in-Recovery Funding. APCo is the primary beneficiary of Appalachian Consumer Rate Relief Funding. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M and OPCo each hold a significant variable interest in AEGCo.
	Sabine is a mining operator providing mining services to SWEPCo. SWEPCo has no equity investment in Sabine but is Sabine's only customer. SWEPCo guarantees the debt obligations and lease obligations of Sabine. Under the terms of the note agreements, substantially all assets are pledged and all rights under the lignite mining agreement are assigned to SWEPCo. The creditors of Sabine have no recourse to any AEP entity other than SWEPCo. Under the provisions of the mining agreement, SWEPCo is required to pay, as a part of the cost of lignite delivered, an amount equal to mining costs plus a management fee. In addition, SWEPCo determines how much coal will be mined each year. Based on these facts, management concluded that SWEPCo is the primary beneficiary and is required to consolidate Sabine. SWEPCo's total billings from Sabine for the three months ended March 31, 2014 and 2013 were $39 million and $44 million, respectively. See the tables below for the classification of Sabine's assets and liabilities on SWEPCo's condensed balance sheets.

	The balances below represent the assets and liabilities of Sabine that are consolidated. These balances include intercompany transactions that are eliminated upon consolidation.
		SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
		VARIABLE INTEREST ENTITIES
		March 31, 2014 and December 31, 2013
		(in thousands)
				Sabine
		ASSETS		2014			2013
		Current Assets		$	61,675		$	66,478
		Net Property, Plant and Equipment			153,928			157,274
		Other Noncurrent Assets			50,140			51,211
		Total Assets		$	265,743		$	274,963

		LIABILITIES AND EQUITY
		Current Liabilities		$	29,257		$	32,812
		Noncurrent Liabilities			236,142			241,673
		Equity			344			478
		Total Liabilities and Equity		$	265,743		$	274,963
	DHLC is a mining operator which sells 50% of the lignite produced to SWEPCo and 50% to CLECO. SWEPCo and CLECO share the executive board seats and voting rights equally. Each entity guarantees 50% of DHLC's debt. SWEPCo and CLECO equally approve DHLC's annual budget. The creditors of DHLC have no recourse to any AEP entity other than SWEPCo. As SWEPCo is the sole equity owner of DHLC, it receives 100% of the management fee. SWEPCo's total billings from DHLC for the three months ended March 31, 2014 and 2013 were $2 million and $18 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 condensed balance sheets.

	SWEPCo's investment in DHLC was:
				31-Mar-14						31-Dec-13
				As Reported on			Maximum			As Reported on			Maximum
				the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in thousands)
		Capital Contribution from SWEPCo		$	7,643		$	7,643		$	7,643		$	7,643
		Retained Earnings			1,910			1,910			1,600			1,600
		SWEPCo's Guarantee of Debt			-			85,190			-			61,348

		Total Investment in DHLC		$	9,553		$	94,743		$	9,243		$	70,591
	AEPSC provides certain managerial and professional services to AEP's subsidiaries. AEP is the sole equity owner of AEPSC. AEP management controls the activities of AEPSC. The costs of the services are based on a direct charge or on a prorated basis and billed to the AEP subsidiary companies at AEPSC's cost. AEP subsidiaries have not provided financial or other support outside of the reimbursement of costs for services rendered. AEPSC finances its operations through cost reimbursement from other AEP subsidiaries. There are no other terms or arrangements between AEPSC and any of the AEP subsidiaries that could require additional financial support from an AEP subsidiary or expose them to losses outside of the normal course of business. AEPSC and its billings are subject to regulation by the FERC. AEP subsidiaries are exposed to losses to the extent they cannot recover the costs of AEPSC through their normal business operations. AEP subsidiaries are considered to have a significant interest in AEPSC due to their activity in AEPSC's cost reimbursement structure. However, AEP subsidiaries do not have control over AEPSC. AEPSC is consolidated by AEP. In the event AEPSC would require financing or other support outside the cost reimbursement billings, this financing would be provided by AEP.

	Total AEPSC billings to the Registrant Subsidiaries were as follows:

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
	The carrying amount and classification of variable interest in AEPSC's accounts payable are as follows:

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520

Significant_Accounting_Matters1

Significant Accounting Matters (Policies)	3 Months Ended
Significant Accounting Matters (Policies)	Mar. 31, 2014
Basis of Accounting	'
	General

	The unaudited condensed consolidated financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

	In the opinion of management, the unaudited condensed consolidated interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of our net income, financial position and cash flows for the interim periods. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2013 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 25, 2014.
Revenue Recognition	'
	Revenue Recognition

	Electricity Supply and Delivery Activities – Transactions with PJM

	Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. For regulated and nonregulated operations, we recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

	APCo, I&M and KPCo sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenue on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.

	AEP's nonregulated subsidiaries also purchase power from PJM and sell power to PJM. With the exception of certain dedicated load bilateral power supply contracts, these transactions are reported as gross purchases and sales.
Earnings Per Share	'
	Earnings Per Share (EPS)
	Basic earnings per common share is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted earnings per common share is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
Appalachian Power Co [Member]	'
Basis of Accounting	'
	General

	The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

	In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014.
Revenue Recognition	'
	Revenue Recognition

	Electricity Supply and Delivery Activities – Transactions with PJM

	Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

	APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenues on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.
Indiana Michigan Power Co [Member]	'
Basis of Accounting	'
	General

	The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

	In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014.
Revenue Recognition	'
	Revenue Recognition

	Electricity Supply and Delivery Activities – Transactions with PJM

	Revenues are recognized from retail and wholesale electricity sales and electricity transmission and distribution delivery services. The Registrant Subsidiaries recognize the revenues on the statements of income upon delivery of the energy to the customer and include unbilled as well as billed amounts.

	APCo and I&M sell power produced at their generation plants to PJM and purchase power from PJM to supply their retail load. These power sales and purchases for each subsidiary's retail load are netted hourly for financial reporting purposes. On an hourly net basis, each subsidiary records sales of power to PJM in excess of purchases of power from PJM as revenues on the statements of income. Also, on an hourly net basis, each subsidiary records purchases of power from PJM to serve retail load in excess of sales of power to PJM as Purchased Electricity for Resale on the statements of income. Upon termination of the Interconnection Agreement, each subsidiary manages and accounts for its purchases and sales with PJM individually based on market prices.
Ohio Power Co [Member]	'
Basis of Accounting	'
	General

	The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

	In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014.
Public Service Co Of Oklahoma [Member]	'
Basis of Accounting	'
	General

	The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

	In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014.
Southwestern Electric Power Co [Member]	'
Basis of Accounting	'
	General

	The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements.

	In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three months ended March 31, 2014 is not necessarily indicative of results that may be expected for the year ending December 31, 2014. The condensed financial statements are unaudited and should be read in conjunction with the audited 2013 financial statements and notes thereto, which are included in the Registrant Subsidiaries' Annual Reports on Form 10-K for the year ended December 31, 2013 as filed with the SEC on February 25, 2014.

Derivatives_and_Hedging_Polici

Derivatives and Hedging (Policies)	3 Months Ended
Derivatives and Hedging (Policies)	Mar. 31, 2014
Derivatives and Hedging	'
	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates. We manage these risks using derivative instruments.
	STRATEGIES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS TO ACHIEVE OBJECTIVES

	Risk Management Strategies

	Our strategy surrounding the use of derivative instruments primarily focuses on managing our risk exposures, future cash flows and creating value utilizing both economic and formal hedging strategies. Our risk management strategies also include the use of derivative instruments for trading purposes, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which we transact. To accomplish our objectives, we 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.

	We enter into power, coal, natural gas, interest rate and, to a lesser extent, heating oil, gasoline and other commodity contracts to manage the risk associated with our energy business. We enter into interest rate derivative contracts in order to manage the interest rate exposure associated with our commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as they are related to energy risk management activities. We also engage in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors.
	Fair Value Hedging Strategies

	We enter 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 our exposure to interest rate risk by converting a portion of our fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	We enter into and designate as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. We monitor the potential impacts of commodity price changes and, where appropriate, enter into derivative transactions to protect profit margins for a portion of future electricity sales and fuel or energy purchases. We do not hedge all commodity price risk.

	Our vehicle fleet and barge operations are exposed to gasoline and diesel fuel price volatility. We enter into financial heating oil and gasoline derivative contracts in order to mitigate price risk of our future fuel purchases. We discontinued cash flow hedge accounting for these derivative contracts effective March 31, 2014. During the three months ended March 31, 2013, we designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. We do not hedge all fuel price risk.

	We enter into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify our exposure to interest rate risk by converting a portion of our floating-rate debt to a fixed rate. We also enter into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. Our forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. We do not hedge all interest rate exposure.

	At times, we are exposed to foreign currency exchange rate risks primarily when we purchase certain fixed assets from foreign suppliers. In accordance with our risk management policy, we may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. We do not hedge all foreign currency exposure.
	ACCOUNTING FOR DERIVATIVE INSTRUMENTS AND THE IMPACT ON OUR FINANCIAL STATEMENTS

	The accounting guidance for “Derivatives and Hedging” requires recognition of all qualifying derivative instruments as either assets or liabilities on the condensed 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 our derivative instruments, we also 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 our 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 our risk management contracts.

	According to the accounting guidance for “Derivatives and Hedging,” we reflect the fair values of our derivative instruments subject to netting agreements with the same counterparty net of related cash collateral. For certain risk management contracts, we 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 condensed statements of income on an accrual basis.

	Our 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, we designate 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
	Accounting for Fair Value Hedging Strategies

	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.

	We record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on our condensed statements of income.
	Accounting for Cash Flow Hedging Strategies

	For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets until the period the hedged item affects Net Income. We recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

	Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on our condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on our condensed balance sheets, depending on the specific nature of the risk being hedged.
	We reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on our condensed statements of income.
	We reclassify gains and losses on interest rate derivative hedges related to our debt financings from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Interest Expense on our condensed statements of income in those periods in which hedged interest payments occur.
	The accumulated gains or losses related to our foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on our condensed balance sheets into Depreciation and Amortization expense on our condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.
	Credit Risk

	We limit credit risk in our 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. We use Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

	When we use standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds our established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with our credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
	Collateral Triggering Events

	Under the tariffs of the RTOs and Independent System Operators (ISOs), a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads, and guaranties for contractual obligations, we are obligated to post an additional amount of collateral if our credit ratings decline below a specified rating threshold. The amount of collateral required fluctuates based on market prices and our total exposure. On an ongoing basis, our risk management organization assesses the appropriateness of these collateral triggering items in contracts. AEP and its subsidiaries have not experienced a downgrade below a specified rating threshold that would require the posting of additional collateral.
	In addition, a majority of our non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, our risk management organization assesses the appropriateness of these cross-default provisions in our contracts.
Appalachian Power Co [Member]	'
Derivatives and Hedging	'
	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
	Accounting for Fair Value Hedging Strategies

	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.

	The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income.
	Accounting for Cash Flow Hedging Strategies

	For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

	Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged.
	The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income.
	The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur.
	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.
	Credit Risk

	AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

	When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
	Collateral Triggering Events

	Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade.
	In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts.
Indiana Michigan Power Co [Member]	'
Derivatives and Hedging	'
	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
	Accounting for Fair Value Hedging Strategies

	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.

	The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income.
	Accounting for Cash Flow Hedging Strategies

	For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

	Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged.
	The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income.
	The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur.
	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.
	Credit Risk

	AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

	When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
	Collateral Triggering Events

	Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade.
	In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts.
Ohio Power Co [Member]	'
Derivatives and Hedging	'
	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
	Accounting for Fair Value Hedging Strategies

	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.

	The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income.
	Accounting for Cash Flow Hedging Strategies

	For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

	Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged.
	The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income.
	The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur.
	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.
	Credit Risk

	AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

	When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
	Collateral Triggering Events

	Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade.
	In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts.
Public Service Co Of Oklahoma [Member]	'
Derivatives and Hedging	'
	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
	Accounting for Fair Value Hedging Strategies

	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.

	The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income.
	Accounting for Cash Flow Hedging Strategies

	For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

	Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged.
	The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income.
	The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur.
	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.
	Credit Risk

	AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

	When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
	Collateral Triggering Events

	Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade.
	In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts.
Southwestern Electric Power Co [Member]	'
Derivatives and Hedging	'
	OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS

	The Registrant Subsidiaries are exposed to certain market risks as major power producers and marketers of wholesale electricity, natural gas, coal and emission allowances. These risks include commodity price risk, interest rate risk, credit risk and, to a lesser extent, foreign currency exchange risk. These risks represent the risk of loss that may impact the Registrant Subsidiaries due to changes in the underlying market prices or rates. AEPSC, on behalf of the Registrant Subsidiaries, manages these risks using derivative instruments.
	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, focusing on seizing market opportunities to create value driven by expected changes in the market prices of the commodities in which AEPSC transacts on behalf of the Registrant Subsidiaries. To accomplish these objectives, AEPSC, on behalf of the Registrant Subsidiaries, primarily employs 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.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into power, 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. AEPSC, on behalf of the Registrant Subsidiaries, enters into interest rate derivative contracts in order to manage the interest rate exposure associated with the Registrant Subsidiaries' commodity portfolio. For disclosure purposes, such risks are grouped as “Commodity,” as these risks are related to energy risk management activities. AEPSC, on behalf of the Registrant Subsidiaries, also engages in risk management of interest rate risk associated with debt financing and foreign currency risk associated with future purchase obligations denominated in foreign currencies. For disclosure purposes, these risks are grouped as “Interest Rate and Foreign Currency.” The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors.
	Fair Value Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, 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 an exposure to interest rate risk by converting a portion of fixed-rate debt to a floating rate. Provided specific criteria are met, these interest rate derivatives are designated as fair value hedges.
	Cash Flow Hedging Strategies

	AEPSC, on behalf of the Registrant Subsidiaries, enters into and designates as cash flow hedges certain derivative transactions for the purchase and sale of power and natural gas (“Commodity”) in order to manage the variable price risk related to the forecasted purchase and sale of these commodities. 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 fuel or energy purchases. The Registrant Subsidiaries do not hedge all commodity price risk.

	The Registrant Subsidiaries' vehicle fleet is exposed to gasoline and diesel fuel price volatility. AEPSC, on behalf of the Registrant Subsidiaries, enters into financial heating oil and gasoline derivative contracts in order to mitigate price risk of future fuel purchases. Cash flow hedge accounting for these derivative contracts was discontinued effective March 31, 2014. During the three months ended March 31, 2013, the Registrant Subsidiaries designated financial heating oil and gasoline derivatives as cash flow hedges. For disclosure purposes, these contracts were included with other hedging activities as “Commodity” as of December 31, 2013. As of March 31, 2014, these contracts will be grouped as “Commodity” with other risk management activities. The Registrant Subsidiaries do not hedge all fuel price risk.

	AEPSC, on behalf of the Registrant Subsidiaries, enters into a variety of interest rate derivative transactions in order to manage interest rate risk exposure. Some interest rate derivative transactions effectively modify exposure to interest rate risk by converting a portion of floating-rate debt to a fixed rate. AEPSC, on behalf of the Registrant Subsidiaries, also enters into interest rate derivative contracts to manage interest rate exposure related to future borrowings of fixed-rate debt. The forecasted fixed-rate debt offerings have a high probability of occurrence as the proceeds will be used to fund existing debt maturities and projected capital expenditures. The Registrant Subsidiaries do not hedge all interest rate exposure.

	At times, the Registrant Subsidiaries 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, AEPSC, on behalf of the Registrant Subsidiaries, may enter into foreign currency derivative transactions to protect against the risk of increased cash outflows resulting from a foreign currency's appreciation against the dollar. The Registrant Subsidiaries 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 condensed balance sheet 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 Registrant Subsidiaries also 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 Registrant Subsidiaries 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 Registrant Subsidiaries 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 condensed 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 condensed 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 condensed statements of income depending on the relevant facts and circumstances. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.”
	Accounting for Fair Value Hedging Strategies

	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.

	The Registrant Subsidiaries record realized and unrealized gains or losses on interest rate swaps that qualify for fair value hedge accounting treatment and any offsetting changes in the fair value of the debt being hedged in Interest Expense on the condensed statements of income.
	Accounting for Cash Flow Hedging Strategies

	For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the Registrant Subsidiaries 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 condensed balance sheets until the period the hedged item affects Net Income. The Registrant Subsidiaries recognize any hedge ineffectiveness in Net Income immediately during the period of change, except in regulated jurisdictions where hedge ineffectiveness is recorded as a regulatory asset (for losses) or a regulatory liability (for gains).

	Realized gains and losses on derivative contracts for the purchase and sale of power, coal and natural gas designated as cash flow hedges are included in Revenues, Fuel and Other Consumables Used for Electric Generation or Purchased Electricity for Resale on the condensed statements of income, or in Regulatory Assets or Regulatory Liabilities on the condensed balance sheets, depending on the specific nature of the risk being hedged.
	The Registrant Subsidiaries reclassify gains and losses on heating oil and gasoline derivative contracts designated as cash flow hedges from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Other Operation expense, Maintenance expense or Depreciation and Amortization expense, as it relates to capital projects, on the condensed statements of income.
	The Registrant Subsidiaries reclassify gains and losses on interest rate derivative hedges related to debt financings from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Interest Expense on the condensed statements of income in those periods in which hedged interest payments occur.
	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets into Depreciation and Amortization expense on the condensed statements of income over the depreciable lives of the fixed assets designated as the hedged items in qualifying foreign currency hedging relationships.
	Credit Risk

	AEPSC, on behalf of the Registrant Subsidiaries, limits credit risk in their 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. AEPSC, on behalf of the Registrant Subsidiaries, uses Moody's, Standard and Poor's and current market-based qualitative and quantitative data as well as financial statements to assess the financial health of counterparties on an ongoing basis.

	When AEPSC, on behalf of the Registrant Subsidiaries, uses standardized master agreements, these agreements may include collateral requirements. These master agreements facilitate the netting of cash flows associated with a single counterparty. Cash, letters of credit and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds the established threshold. The threshold represents an unsecured credit limit which may be supported by a parental/affiliate guaranty, as determined in accordance with AEP's credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
	Collateral Triggering Events

	Under the tariffs of the RTOs and Independent System Operators (ISOs) and a limited number of derivative and non-derivative contracts primarily related to competitive retail auction loads, the Registrant Subsidiaries are obligated to post an additional amount of collateral if certain credit ratings decline below investment grade. The amount of collateral required fluctuates based on market prices and total exposure. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these collateral triggering items in contracts. The Registrant Subsidiaries have not experienced a downgrade below investment grade.
	In addition, a majority of the Registrant Subsidiaries' non-exchange traded commodity contracts contain cross-default provisions that, if triggered, would permit the counterparty to declare a default and require settlement of the outstanding payable. These cross-default provisions could be triggered if there was a non-performance event by Parent or the obligor under outstanding debt or a third party obligation in excess of $50 million. On an ongoing basis, AEP's risk management organization assesses the appropriateness of these cross-default provisions in the contracts.

Fair_Value_Measurements_Polici

Fair Value Measurements (Policies)	3 Months Ended
Fair Value Measurements (Policies)	Mar. 31, 2014
Valuation Techniques	'
	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations, Energy Supply and Finance groups in accordance with our established risk management policies as approved by the Finance Committee of our Board of Directors. Our market risk oversight staff independently monitors our 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 daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to AEP Energy Supply's President and Vice President.

	For our 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. We verify our price curves using these broker quotes and classify these fair values within Level 2 when substantially all of the fair value can be corroborated. We typically obtain multiple broker quotes, which are nonbinding in nature, but are based on recent trades in the marketplace. When multiple broker quotes are obtained, we average the quoted bid and ask prices. In certain circumstances, we may discard a broker quote if it is a clear outlier. We use a historical correlation analysis between the broker quoted location and the illiquid locations. If the points are highly correlated, we include these locations 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 our contracts being classified as Level 3 is the inability to substantiate our energy price curves in the market. A significant portion of our Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	We utilize our trustee's external pricing service in our estimate of the fair value of the underlying investments held in the nuclear trusts. Our investment managers review and validate the prices utilized by the trustee to determine fair value. We perform our own valuation testing to verify the fair values of the securities. We receive audit reports of our trustee's operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

	Assets in the nuclear trusts, Cash and Cash Equivalents and Other Temporary Investments 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	'
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that we could realize in a current market exchange.

Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	'
	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

	Nuclear decommissioning and spent nuclear fuel trust funds represent funds that regulatory commissions allow us 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 or its affiliates.
	Withdrawals permitted only for payment of decommissioning costs and trust expenses.


	We maintain trust records for each regulatory jurisdiction. 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 trust funds for decommissioning nuclear facilities and for the disposal of SNF 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 fixed income 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 equity and fixed income investments held in these trusts and generally intends to sell fixed income 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 the trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction's liabilities. Regulatory approval is required to withdraw decommissioning funds.

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. Our 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 our valuation techniques.
Appalachian Power Co [Member]	'
Valuation Techniques	'
	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	'
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

Fair Value Assets and Liabilities Measured on Recurring Basis	'
	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management's valuation techniques.
Indiana Michigan Power Co [Member]	'
Valuation Techniques	'
	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	AEP utilizes its trustee's external pricing service in its estimate of the fair value of the underlying investments held in the nuclear trusts. AEP's investment managers review and validate the prices utilized by the trustee to determine fair value. AEP's management performs its own valuation testing to verify the fair values of the securities. AEP receives audit reports of the trustee's operating controls and valuation processes. The trustee uses multiple pricing vendors for the assets held in the trusts.

	Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	'
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

Trust Assets for Decommissioning and Spent Nuclear Fuel Disposal	'
	Fair Value Measurements of Trust Assets for Decommissioning and SNF Disposal

	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 or its affiliates.
	Withdrawals permitted only for payment of decommissioning costs and trust expenses.


	I&M maintains trust records for each regulatory jurisdiction. 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 trust funds for decommissioning nuclear facilities and for the disposal of SNF 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 fixed income 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 equity and fixed income investments held in these trusts and generally intends to sell fixed income securities in an unrealized loss position as part of a tax optimization strategy. Impairments reduce the cost basis of the securities which will affect any future unrealized gain or realized gain or loss due to the adjusted cost of investment. I&M records unrealized gains and other-than-temporary impairments from securities in these trust funds as adjustments to the regulatory liability account for the nuclear decommissioning trust funds and to regulatory assets or liabilities for the SNF disposal trust funds in accordance with their treatment in rates. Consequently, changes in fair value of trust assets do not affect earnings or AOCI. The trust assets are recorded by jurisdiction and may not be used for another jurisdiction's liabilities. Regulatory approval is required to withdraw decommissioning funds.

Fair Value Assets and Liabilities Measured on Recurring Basis	'
	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management's valuation techniques.
Ohio Power Co [Member]	'
Valuation Techniques	'
	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.
	Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	'
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

Fair Value Assets and Liabilities Measured on Recurring Basis	'
	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management's valuation techniques.
Public Service Co Of Oklahoma [Member]	'
Valuation Techniques	'
	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.
Fair Values of Long-term Debt	'
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

Fair Value Assets and Liabilities Measured on Recurring Basis	'
	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management's valuation techniques.
Southwestern Electric Power Co [Member]	'
Valuation Techniques	'
	Fair Value Hierarchy and Valuation Techniques

	The accounting guidance for “Fair Value Measurements and Disclosures” establishes a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). Where observable inputs are available for substantially the full term of the asset or liability, the instrument is categorized in Level 2. When quoted market prices are not available, pricing may be completed using comparable securities, dealer values, operating data and general market conditions to determine fair value. Valuation models utilize various inputs such as commodity, interest rate and, to a lesser degree, volatility and credit that include quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, market corroborated inputs (i.e. inputs derived principally from, or correlated to, observable market data) and other observable inputs for the asset or liability. The amount of risk taken is determined by the Commercial Operations and Finance groups in accordance with established risk management policies as approved by the Finance Committee of AEP's Board of Directors. The AEP System'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) various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC's Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer.

	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 the contracts being classified as Level 3 is the inability to substantiate energy price curves in the market. A significant portion of the Level 3 instruments have been economically hedged which greatly limits potential earnings volatility.

	Assets in the nuclear trusts, Restricted Cash for Securitized Funding and Cash and Cash Equivalents 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 equivalents funds. Fixed income securities do not trade on an exchange and do not have an official closing price but their valuation inputs are based on observable market data. Pricing vendors calculate bond valuations using financial models and matrices. The models use observable inputs including yields on benchmark securities, quotes by securities brokers, rating agency actions, discounts or premiums on securities compared to par prices, changes in yields for U.S. Treasury securities, corporate actions by bond issuers, prepayment schedules and histories, economic events and, for certain securities, adjustments to yields to reflect changes in the rate of inflation. Other securities with model-derived valuation inputs that are observable are also classified as Level 2 investments. Investments with unobservable valuation inputs are classified as Level 3 investments.
Fair Values of Long-term Debt	'
	Fair Value Measurements of Long-term Debt

	The fair values of Long-term Debt are based on quoted market prices, without credit enhancements, for the same or similar issues and the current interest rates offered for instruments with similar maturities classified as Level 2 measurement inputs. These instruments are not marked-to-market. The estimates presented are not necessarily indicative of the amounts that could be realized in a current market exchange.

Fair Value Assets and Liabilities Measured on Recurring Basis	'
	As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management's assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management's valuation techniques.

Income_Taxes_Policies

Income Taxes (Policies)	3 Months Ended
Income Taxes (Policies)	Mar. 31, 2014
Income Tax Policy	'
	AEP System Tax Allocation Agreement

	We, along with our subsidiaries, file a consolidated federal income tax return. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to our subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Appalachian Power Co [Member]	'
Income Tax Policy	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Indiana Michigan Power Co [Member]	'
Income Tax Policy	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Ohio Power Co [Member]	'
Income Tax Policy	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Public Service Co Of Oklahoma [Member]	'
Income Tax Policy	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Southwestern Electric Power Co [Member]	'
Income Tax Policy	'
	AEP System Tax Allocation Agreement

	The Registrant Subsidiaries join in the filing of a consolidated federal income tax return with their affiliates in the AEP System. The allocation of the AEP System's current consolidated federal income tax to the AEP System companies allocates the benefit of current tax losses to the AEP System companies giving rise to such losses in determining their current tax expense. The tax benefit of the Parent is allocated to its subsidiaries with taxable income. With the exception of the loss of the Parent, the method of allocation reflects a separate return result for each company in the consolidated group.

Variable_Interest_Entities_Pol

Variable Interest Entities (Policies)	3 Months Ended
Variable Interest Entities (Policies)	Mar. 31, 2014
Variable Interest Entities	'
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether we are the primary beneficiary of a VIE, we consider factors such as equity at risk, the amount of the VIE's variability we absorb, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. We believe that significant assumptions and judgments were applied consistently.
Appalachian Power Co [Member]	'
Variable Interest Entities	'
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.
Indiana Michigan Power Co [Member]	'
Variable Interest Entities	'
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.
Ohio Power Co [Member]	'
Variable Interest Entities	'
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.
Public Service Co Of Oklahoma [Member]	'
Variable Interest Entities	'
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.
Southwestern Electric Power Co [Member]	'
Variable Interest Entities	'
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether they are the primary beneficiary of a VIE, management considers for each Registrant Subsidiary factors such as equity at risk, the amount of the VIE's variability the Registrant Subsidiary absorbs, guarantees of indebtedness, voting rights including kick-out rights, the power to direct the VIE, variable interests held by related parties and other factors. Management believes that significant assumptions and judgments were applied consistently. In addition, the Registrant Subsidiaries have not provided financial or other support to any VIE that was not previously contractually required.

Significant_Accounting_Matters2

Significant Accounting Matters (Tables)	3 Months Ended
Significant Accounting Matters (Tables)	Mar. 31, 2014
Basic and Diluted EPS Calculations	'
				Three Months Ended March 31,
				2014				2013
				(in millions, except per share data)
						$/share				$/share
		Earnings Attributable to AEP Common Shareholders		$	560			$	363

		Weighted Average Number of Basic Shares Outstanding			487.9	$	1.15		485.8	$	0.75
		Weighted Average Dilutive Effect of:
			Restricted Stock Units		0.4		-		0.5		-
		Weighted Average Number of Diluted Shares Outstanding			488.3	$	1.15		486.3	$	0.75

Comprehensive_Income_Tables

Comprehensive Income (Tables)	3 Months Ended
Comprehensive Income (Tables)	Mar. 31, 2014
Changes in Accumulated Other Comprehensive Income by Component	'
	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 2014

				Cash Flow Hedges
							Interest Rate and			Securities			Pension
				Commodity			Foreign Currency			Available for Sale			and OPEB			Total
				(in millions)
	Balance in AOCI as of December 31, 2013			$	-		$	-23		$	7		$	-99		$	-115
	Change in Fair Value Recognized in AOCI				-14			-			-			-			-14
	Amounts Reclassified from AOCI				18			1			-			1			20
	Net Current Period Other
			Comprehensive Income		4			1			-			1			6
	Balance in AOCI as of March 31, 2014			$	4		$	-22		$	7		$	-98		$	-109

	Changes in Accumulated Other Comprehensive Income (Loss) by Component
	For the Three Months Ended March 31, 2013

				Cash Flow Hedges
							Interest Rate and			Securities			Pension
				Commodity			Foreign Currency			Available for Sale			and OPEB			Total
				(in millions)
	Balance in AOCI as of December 31, 2012			$	-8		$	-30		$	4		$	-303		$	-337
	Change in Fair Value Recognized in AOCI				18			3			1			-			22
	Amounts Reclassified from AOCI				2			1			-			6			9
	Net Current Period Other
			Comprehensive Income		20			4			1			6			31
	Balance in AOCI as of March 31, 2013			$	12		$	-26		$	5		$	-297		$	-306
Reclassifications from Accumulated Other Comprehensive Income	'
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in millions)
		Commodity:
				Vertically Integrated Utilities Revenues		$	-		$	-
				Generation & Marketing Revenues			-			-3
				Purchased Electricity for Resale			31			6
				Property, Plant and Equipment			-			-
				Regulatory Assets/(Liabilities), Net (a)			-3			-
		Subtotal - Commodity					28			3

		Interest Rate and Foreign Currency:
				Interest Expense			2			2
		Subtotal - Interest Rate and Foreign Currency					2			2

		Reclassifications from AOCI, before Income Tax (Expense) Credit					30			5
		Income Tax (Expense) Credit					11			2
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					19			3

		Gains and Losses on Securities Available for Sale
		Interest Income					-			-
		Interest Expense					-			-
		Reclassifications from AOCI, before Income Tax (Expense) Credit					-			-
		Income Tax (Expense) Credit					-			-
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-			-

		Pension and OPEB
		Amortization of Prior Service Cost (Credit)					-5			-5
		Amortization of Actuarial (Gains)/Losses					7			14
		Reclassifications from AOCI, before Income Tax (Expense) Credit					2			9
		Income Tax (Expense) Credit					1			3
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					1			6

		Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	20		$	9
	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Appalachian Power Co [Member]	'
Changes in Accumulated Other Comprehensive Income by Component	'
	APCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2013			$	94		$	3,090		$	-233		$	2,951
		Change in Fair Value Recognized in AOCI				1,583			-			-			1,583
		Amounts Reclassified from AOCI				-1,590			253			-333			-1,670
		Net Current Period Other
				Comprehensive Income		-7			253			-333			-87
		Balance in AOCI as of March 31, 2014			$	87		$	3,343		$	-566		$	2,864

	APCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	-644		$	2,077		$	-31,331		$	-29,898
		Change in Fair Value Recognized in AOCI				794			-1			-			793
		Amounts Reclassified from AOCI				211			254			358			823
		Net Current Period Other
				Comprehensive Income		1,005			253			358			1,616
		Balance in AOCI as of March 31, 2013			$	361		$	2,330		$	-30,973		$	-28,282
Reclassifications from Accumulated Other Comprehensive Income	'
	APCo
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Electric Generation, Transmission and Distribution Revenues		$	-		$	20
				Purchased Electricity for Resale			-462			57
				Other Operation Expense			-10			-11
				Maintenance Expense			-20			-16
				Property, Plant and Equipment			-17			-14
				Regulatory Assets/(Liabilities), Net (a)			-1,937			289
		Subtotal - Commodity					-2,446			325

		Interest Rate and Foreign Currency:
				Interest Expense			390			390
		Subtotal - Interest Rate and Foreign Currency					390			390

		Reclassifications from AOCI, before Income Tax (Expense) Credit					-2,056			715
		Income Tax (Expense) Credit					-719			250
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-1,337			465

		Pension and OPEB
		Amortization of Prior Service Cost (Credit)					-1,282			-1,282
		Amortization of Actuarial (Gains)/Losses					770			1,833
		Reclassifications from AOCI, before Income Tax (Expense) Credit					-512			551
		Income Tax (Expense) Credit					-179			193
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-333			358

		Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	-1,670		$	823
	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Indiana Michigan Power Co [Member]	'
Changes in Accumulated Other Comprehensive Income by Component	'
	I&M
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2013			$	46		$	-15,976		$	421		$	-15,509
		Change in Fair Value Recognized in AOCI				1,062			-			-			1,062
		Amounts Reclassified from AOCI				-1,047			410			43			-594
		Net Current Period Other
				Comprehensive Income		15			410			43			468
		Balance in AOCI as of March 31, 2014			$	61		$	-15,566		$	464		$	-15,041

	I&M
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	-446		$	-19,647		$	-8,790		$	-28,883
		Change in Fair Value Recognized in AOCI				532			2,249			-			2,781
		Amounts Reclassified from AOCI				150			192			176			518
		Net Current Period Other
				Comprehensive Income		682			2,441			176			3,299
		Balance in AOCI as of March 31, 2013			$	236		$	-17,206		$	-8,614		$	-25,584
Reclassifications from Accumulated Other Comprehensive Income	'
	I&M
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Electric Generation, Transmission and Distribution Revenues		$	-		$	52
				Purchased Electricity for Resale			-717			149
				Other Operation Expense			-7			-7
				Maintenance Expense			-7			-7
				Property, Plant and Equipment			-10			-7
				Regulatory Assets/(Liabilities), Net (a)			-870			50
		Subtotal - Commodity					-1,611			230

		Interest Rate and Foreign Currency:
				Interest Expense			631			296
		Subtotal - Interest Rate and Foreign Currency					631			296

		Reclassifications from AOCI, before Income Tax (Expense) Credit					-980			526
		Income Tax (Expense) Credit					-343			184
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-637			342

		Pension and OPEB
		Amortization of Prior Service Cost (Credit)					-199			-199
		Amortization of Actuarial (Gains)/Losses					265			469
		Reclassifications from AOCI, before Income Tax (Expense) Credit					66			270
		Income Tax (Expense) Credit					23			94
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					43			176

		Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	-594		$	518
	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Ohio Power Co [Member]	'
Changes in Accumulated Other Comprehensive Income by Component	'
	OPCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2013			$	105		$	6,974		$	-		$	7,079
		Change in Fair Value Recognized in AOCI				-			-			-			-
		Amounts Reclassified from AOCI				-105			-343			-			-448
		Net Current Period Other
				Comprehensive Income		-105			-343			-			-448
		Balance in AOCI as of March 31, 2014			$	-		$	6,631		$	-		$	6,631

	OPCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	-912		$	8,095		$	-172,908		$	-165,725
		Change in Fair Value Recognized in AOCI				1,102			-			-			1,102
		Amounts Reclassified from AOCI				304			-340			3,269			3,233
		Net Current Period Other
				Comprehensive Income		1,406			-340			3,269			4,335
		Balance in AOCI as of March 31, 2013			$	494		$	7,755		$	-169,639		$	-161,390
Reclassifications from Accumulated Other Comprehensive Income	'
	OPCo
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Electric Generation, Transmission and Distribution Revenues		$	-		$	134
				Purchased Electricity for Resale			-			382
				Other Operation Expense			-11			-18
				Maintenance Expense			-11			-12
				Property, Plant and Equipment			-18			-19
				Regulatory Assets/(Liabilities), Net (a)			-122			-
		Subtotal - Commodity					-162			467

		Interest Rate and Foreign Currency:
				Depreciation and Amortization Expense			-3			2
				Interest Expense			-524			-524
		Subtotal - Interest Rate and Foreign Currency					-527			-522

		Reclassifications from AOCI, before Income Tax (Expense) Credit					-689			-55
		Income Tax (Expense) Credit					-241			-19
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-448			-36

		Pension and OPEB
		Amortization of Prior Service Cost (Credit)					-			-1,468
		Amortization of Actuarial (Gains)/Losses					-			6,497
		Reclassifications from AOCI, before Income Tax (Expense) Credit					-			5,029
		Income Tax (Expense) Credit					-			1,760
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-			3,269

		Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	-448		$	3,233
	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Public Service Co Of Oklahoma [Member]	'
Changes in Accumulated Other Comprehensive Income by Component	'
	PSO
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and
					Commodity			Foreign Currency			Total

					(in thousands)
		Balance in AOCI as of December 31, 2013			$	57		$	5,701		$	5,758
		Change in Fair Value Recognized in AOCI				-			-			-
		Amounts Reclassified from AOCI				-57			-189			-246
		Net Current Period Other
				Comprehensive Income		-57			-189			-246
		Balance in AOCI as of March 31, 2014			$	-		$	5,512		$	5,512

	PSO
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and
					Commodity			Foreign Currency			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	21		$	6,460		$	6,481
		Change in Fair Value Recognized in AOCI				36			-			36
		Amounts Reclassified from AOCI				-13			-190			-203
		Net Current Period Other
				Comprehensive Income		23			-190			-167
		Balance in AOCI as of March 31, 2013			$	44		$	6,270		$	6,314
Reclassifications from Accumulated Other Comprehensive Income	'
	PSO
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Other Operation Expense		$	-8		$	-9
				Maintenance Expense			-9			-4
				Property, Plant and Equipment			-13			-7
				Regulatory Assets/(Liabilities), Net (a)			-58			-
		Subtotal - Commodity					-88			-20

		Interest Rate and Foreign Currency:
				Interest Expense			-292			-292
		Subtotal - Interest Rate and Foreign Currency					-292			-292

		Reclassifications from AOCI, before Income Tax (Expense) Credit					-380			-312
		Income Tax (Expense) Credit					-134			-109
		Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	-246		$	-203
	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Southwestern Electric Power Co [Member]	'
Changes in Accumulated Other Comprehensive Income by Component	'
	SWEPCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2014

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2013			$	66		$	-13,304		$	4,794		$	-8,444
		Change in Fair Value Recognized in AOCI				-			-			-			-
		Amounts Reclassified from AOCI				-66			568			-234			268
		Net Current Period Other
				Comprehensive Income		-66			568			-234			268
		Balance in AOCI as of March 31, 2014			$	-		$	-12,736		$	4,560		$	-8,176

	SWEPCo
		Changes in Accumulated Other Comprehensive Income (Loss) by Component
		For the Three Months Ended March 31, 2013

					Cash Flow Hedges
								Interest Rate and			Pension
					Commodity			Foreign Currency			and OPEB			Total
					(in thousands)
		Balance in AOCI as of December 31, 2012			$	22		$	-15,571		$	-2,311		$	-17,860
		Change in Fair Value Recognized in AOCI				44			-			-			44
		Amounts Reclassified from AOCI				-15			567			-63			489
		Net Current Period Other
				Comprehensive Income		29			567			-63			533
		Balance in AOCI as of March 31, 2013			$	51		$	-15,004		$	-2,374		$	-17,327
Reclassifications from Accumulated Other Comprehensive Income	'
	SWEPCo
		Reclassifications from Accumulated Other Comprehensive Income (Loss)
		For the Three Months Ended March 31, 2014 and 2013

						Amount of (Gain) Loss
						Reclassified from AOCI

						Three Months Ended March 31,
						2014			2013
		Gains and Losses on Cash Flow Hedges				(in thousands)
		Commodity:
				Other Operation Expense		$	-13		$	-10
				Maintenance Expense			-10			-6
				Property, Plant and Equipment			-11			-7
				Regulatory Assets/(Liabilities), Net (a)			-67			-
		Subtotal - Commodity					-101			-23

		Interest Rate and Foreign Currency:
				Interest Expense			872			872
		Subtotal - Interest Rate and Foreign Currency					872			872

		Reclassifications from AOCI, before Income Tax (Expense) Credit					771			849
		Income Tax (Expense) Credit					269			297
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					502			552

		Pension and OPEB
		Amortization of Prior Service Cost (Credit)					-478			-445
		Amortization of Actuarial (Gains)/Losses					118			348
		Reclassifications from AOCI, before Income Tax (Expense) Credit					-360			-97
		Income Tax (Expense) Credit					-126			-34
		Reclassifications from AOCI, Net of Income Tax (Expense) Credit					-234			-63

		Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit				$	268		$	489
	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

Rate_Matters_Tables

Rate Matters (Tables)	3 Months Ended
Rate Matters (Tables)	Mar. 31, 2014
Regulatory Assets Not Yet Being Recovered	'
	Regulatory Assets Not Yet Being Recovered
					March 31,		December 31,
					2014		2013
		Noncurrent Regulatory Assets			(in millions)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Earning a Return
			Storm Related Costs		$	21	$	22
			Ohio Economic Development Rider			-		14
			Other Regulatory Assets Not Yet Being Recovered			-		4
		Regulatory Assets Currently Not Earning a Return
			Storm Related Costs			104		161
			Indiana Under-Recovered Capacity Costs			28		22
			IGCC Pre-Construction Costs			21		-
			Expanded Net Energy Charge - Coal Inventory			19		21
			Mountaineer Carbon Capture and Storage Product Validation Facility			13		13
			Ormet Special Rate Recovery Mechanism			10		36
			Other Regulatory Assets Not Yet Being Recovered			34		37
		Total Regulatory Assets Not Yet Being Recovered			$	250	$	330
Appalachian Power Co [Member]	'
Regulatory Assets Not Yet Being Recovered	'
					APCo
					March 31,		December 31,
					2014		2013
		Noncurrent Regulatory Assets			(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Not Earning a Return
			Storm Related Costs		$	65,206	$	65,206
			IGCC Pre-Construction Costs			20,528		-
			Expanded Net Energy Charge - Coal Inventory			18,818		20,528
			Mountaineer Carbon Capture and Storage
				Product Validation Facility		13,264		13,264
			Virginia Demand Response Program Costs			5,897		5,012
			Transmission Agreement Phase-In			3,450		3,313
			Virginia Environmental Rate Adjustment Clause			1,941		2,440
			Mountaineer Carbon Capture and Storage
				Commercial Scale Facility		1,287		1,287
			Other Regulatory Assets Not Yet Being Recovered			513		168
		Total Regulatory Assets Not Yet Being Recovered			$	130,904	$	111,218
Indiana Michigan Power Co [Member]	'
Regulatory Assets Not Yet Being Recovered	'
					I&M
					March 31,		December 31,
					2014		2013
		Noncurrent Regulatory Assets			(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Not Earning a Return
			Indiana Under-Recovered Capacity Costs		$	28,149	$	21,945
			Cook Plant Turbine			4,238		3,452
			Stranded Costs on Abandoned Plants			3,897		3,896
			Storm Related Costs			751		1,836
			Indiana Deferred Cook Plant Life Cycle Management Project Costs			-		4,093
			Other Regulatory Assets Not Yet Being Recovered			694		164
		Total Regulatory Assets Not Yet Being Recovered			$	37,729	$	35,386
Ohio Power Co [Member]	'
Regulatory Assets Not Yet Being Recovered	'
					OPCo
					March 31,		December 31,
					2014		2013
		Noncurrent Regulatory Assets			(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Earning a Return
			Economic Development Rider		$	-	$	13,854
		Regulatory Assets Currently Not Earning a Return
			Ormet Special Rate Recovery Mechanism			10,483		35,631
			Storm Related Costs			1,635		57,589
		Total Regulatory Assets Not Yet Being Recovered			$	12,118	$	107,074
Public Service Co Of Oklahoma [Member]	'
Regulatory Assets Not Yet Being Recovered	'
					PSO
					March 31,		December 31,
					2014		2013
		Noncurrent Regulatory Assets			(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Not Earning a Return
			Storm Related Costs		$	19,093	$	18,743
			Other Regulatory Assets Not Yet Being Recovered			1,079		845
		Total Regulatory Assets Not Yet Being Recovered			$	20,172	$	19,588
Southwestern Electric Power Co [Member]	'
Regulatory Assets Not Yet Being Recovered	'
					SWEPCo
					March 31,		December 31,
					2014		2013
		Noncurrent Regulatory Assets			(in thousands)
		Regulatory assets not yet being recovered pending future proceedings:

		Regulatory Assets Currently Not Earning a Return
			Rate Case Expenses		$	7,930	$	7,934
			Mountaineer Carbon Capture and Storage
				Commercial Scale Facility		1,143		1,143
			Other Regulatory Assets Not Yet Being Recovered			2,025		1,951
		Total Regulatory Assets Not Yet Being Recovered			$	11,098	$	11,028

Commitments_Guarantees_and_Con1

Commitments, Guarantees and Contingencies (Tables)	3 Months Ended
Commitments, Guarantees and Contingencies (Tables)	Mar. 31, 2014
Appalachian Power Co [Member]	'
Pollution Control Bonds Supported by Bilateral Letters of Credit	'
					Bilateral		Maturity of
			Pollution		Letters		Bilateral Letters
		Company	Control Bonds		of Credit		of Credit
			(in thousands)
		APCo	$	229,650	$	232,293	March 2016 to March 2017
		I&M		77,000		77,886	Mar-15
Maximum Potential Loss on Master Lease Agreements	'
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
Indiana Michigan Power Co [Member]	'
Maximum Future Payments of Letters of Credit	'
		Company	Amount		Maturity
			(in thousands)
		I&M	$	150	Mar-15
		OPCo		3,081	Jun-14
Pollution Control Bonds Supported by Bilateral Letters of Credit	'
					Bilateral		Maturity of
			Pollution		Letters		Bilateral Letters
		Company	Control Bonds		of Credit		of Credit
			(in thousands)
		APCo	$	229,650	$	232,293	March 2016 to March 2017
		I&M		77,000		77,886	Mar-15
Maximum Potential Loss on Master Lease Agreements	'
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
Ohio Power Co [Member]	'
Maximum Future Payments of Letters of Credit	'
		Company	Amount		Maturity
			(in thousands)
		I&M	$	150	Mar-15
		OPCo		3,081	Jun-14
Maximum Potential Loss on Master Lease Agreements	'
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
Public Service Co Of Oklahoma [Member]	'
Maximum Potential Loss on Master Lease Agreements	'
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486
Southwestern Electric Power Co [Member]	'
Maximum Potential Loss on Master Lease Agreements	'
			Maximum
		Company	Potential Loss
			(in thousands)
		APCo	$	3,772
		I&M		2,580
		OPCo		4,384
		PSO		1,347
		SWEPCo		2,486

Benefit_Plans_Tables

Benefit Plans (Tables)	3 Months Ended
Benefit Plans (Tables)	Mar. 31, 2014
Components of Net Periodic Benefit Cost	'
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in millions)
	Service Cost	$	18	$	17	$	4	$	6
	Interest Cost		55		50		17		18
	Expected Return on Plan Assets		-66		-69		-28		-27
	Amortization of Prior Service Cost (Credit)		1		1		-17		-17
	Amortization of Net Actuarial Loss		31		46		5		16
	Net Periodic Benefit Cost (Credit)	$	39	$	45	$	-19	$	-4
Appalachian Power Co [Member]	'
Components of Net Periodic Benefit Cost	'
	APCo
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	1,759	$	1,543	$	362	$	641
	Interest Cost		7,406		6,916		3,197		3,363
	Expected Return on Plan Assets		-8,482		-9,260		-4,633		-4,536
	Amortization of Prior Service Cost (Credit)		50		49		-2,513		-2,512
	Amortization of Net Actuarial Loss		4,148		6,256		1,146		3,062
	Net Periodic Benefit Cost (Credit)	$	4,881	$	5,504	$	-2,441	$	18
Indiana Michigan Power Co [Member]	'
Components of Net Periodic Benefit Cost	'
	I&M
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	2,517	$	2,184	$	487	$	805
	Interest Cost		6,573		6,025		1,909		2,055
	Expected Return on Plan Assets		-7,748		-8,207		-3,364		-3,296
	Amortization of Prior Service Cost (Credit)		49		49		-2,355		-2,355
	Amortization of Net Actuarial Loss		3,646		5,422		592		1,882
	Net Periodic Benefit Cost (Credit)	$	5,037	$	5,473	$	-2,731	$	-909
Ohio Power Co [Member]	'
Components of Net Periodic Benefit Cost	'
	OPCo
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	1,285	$	2,372	$	256	$	1,300
	Interest Cost		5,526		10,292		1,901		4,447
	Expected Return on Plan Assets		-6,607		-15,141		-3,380		-6,238
	Amortization of Prior Service Cost (Credit)		39		71		-1,731		-3,231
	Amortization of Net Actuarial Loss		3,106		9,309		595		4,041
	Net Periodic Benefit Cost (Credit)	$	3,349	$	6,903	$	-2,359	$	319
Public Service Co Of Oklahoma [Member]	'
Components of Net Periodic Benefit Cost	'
	PSO
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	1,302	$	1,391	$	210	$	343
	Interest Cost		3,014		2,748		893		948
	Expected Return on Plan Assets		-3,651		-3,918		-1,575		-1,522
	Amortization of Prior Service Cost (Credit)		74		74		-1,072		-1,072
	Amortization of Net Actuarial Loss		1,688		2,461		277		869
	Net Periodic Benefit Cost (Credit)	$	2,427	$	2,756	$	-1,267	$	-434
Southwestern Electric Power Co [Member]	'
Components of Net Periodic Benefit Cost	'
	SWEPCo
						Other Postretirement
		Pension Plans				Benefit Plans
		Three Months Ended March 31,				Three Months Ended March 31,
		2014		2013		2014		2013
		(in thousands)
	Service Cost	$	1,655	$	1,753	$	253	$	423
	Interest Cost		3,163		2,864		998		1,075
	Expected Return on Plan Assets		-3,857		-4,127		-1,754		-1,720
	Amortization of Prior Service Cost (Credit)		87		87		-1,289		-1,288
	Amortization of Net Actuarial Loss		1,761		2,553		309		982
	Net Periodic Benefit Cost (Credit)	$	2,809	$	3,130	$	-1,483	$	-528

Business_Segments_Tables

Business Segments (Tables)	3 Months Ended
Business Segments (Tables)	Mar. 31, 2014
Business Segments (Tables) [Abstract]	'
Reportable Segment Information	'
							Transmission
				Vertically			and		AEP		Generation					Corporate
				Integrated			Distribution		Transmission		&			AEP River		and Other		Reconciling
				Utilities			Utilities		Holdco		Marketing			Operations		(a)		Adjustments			Consolidated

				(in millions)
	Three Months Ended March 31, 2014
	Revenues from:
			External Customers	$	2,549	(b)	$	1,161	$	12	$	821	(b)	$	146	$	10	$	-51	(c)	$	4,648
			Other Operating Segments		37	(b)		54		16		430	(b)		19		16		-572			-
	Total Revenues			$	2,586		$	1,215	$	28	$	1,251		$	165	$	26	$	-623		$	4,648

	Net Income (Loss)			$	279		$	97	$	24	$	163		$	3	$	-5	$	-		$	561

							Transmission
				Vertically			and		AEP		Generation					Corporate
				Integrated			Distribution		Transmission		&			AEP River		and Other		Reconciling
				Utilities			Utilities		Holdco		Marketing			Operations		(a)		Adjustments			Consolidated

				(in millions)
	Three Months Ended March 31, 2013
	Revenues from:
			External Customers	$	2,356		$	1,090	$	3	$	258		$	128	$	5	$	-14	(c)	$	3,826
			Other Operating Segments		159			44		5		662			5		13		-888			-
	Total Revenues			$	2,515		$	1,134	$	8	$	920		$	133	$	18	$	-902		$	3,826

	Net Income (Loss)			$	181		$	87	$	12	$	85		$	-2	$	1	$	-		$	364
							Transmission
				Vertically			and		AEP		Generation					Corporate		Reconciling
				Integrated			Distribution		Transmission		&			AEP River		and Other		Adjustments
				Utilities			Utilities		Holdco		Marketing			Operations		(a)		(d)			Consolidated

				(in millions)
	31-Mar-14
	Total Property, Plant and Equipment			$	37,923		$	12,339	$	1,842	$	8,302		$	639	$	321	$	-272		$	61,094
	Accumulated Depreciation and
		Amortization			12,424			3,382		13		3,460			197		176		-88			19,564
	Total Property, Plant and
		Equipment - Net		$	25,499		$	8,957	$	1,829	$	4,842		$	442	$	145	$	-184		$	41,530

	Total Assets			$	32,997		$	13,899	$	2,460	$	6,354		$	659	$	20,275	$	-19,606	(e)	$	57,038

							Transmission
				Vertically			and		AEP		Generation					Corporate		Reconciling
				Integrated			Distribution		Transmission		&			AEP River		and Other		Adjustments
				Utilities			Utilities		Holdco		Marketing			Operations		(a)		(d)			Consolidated

				(in millions)
	31-Dec-13
	Total Property, Plant and Equipment			$	37,545		$	12,143	$	1,636	$	8,277		$	638	$	315	$	-269		$	60,285
	Accumulated Depreciation and
		Amortization			12,250			3,342		10		3,409			189		173		-85			19,288
	Total Property, Plant and
		Equipment - Net		$	25,295		$	8,801	$	1,626	$	4,868		$	449	$	142	$	-184		$	40,997

	Total Assets			$	32,791		$	14,165	$	2,245	$	6,426		$	673	$	19,645	$	-19,531	(e)	$	56,414
	(a) Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense 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.
	(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)	3 Months Ended
Derivatives and Hedging (Tables)	Mar. 31, 2014
Notional Volume of Derivative Instruments	'
		Notional Volume of Derivative Instruments

					Volume
					March 31,			December 31,			Unit of
					2014			2013			Measure
		Primary Risk Exposure			(in millions)
		Commodity:
			Power			320			406		MWhs
			Coal			4			4		Tons
			Natural Gas			123			127		MMBtus
			Heating Oil and Gasoline			4			6		Gallons
			Interest Rate		$	192		$	191		USD

		Interest Rate and Foreign Currency			$	819		$	820		USD
Fair Value of Derivative Instruments	'
	Fair Value of Derivative Instruments
	31-Mar-14

														Gross Amounts		Gross			Net Amounts of
				Risk Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign				Liabilities		Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in millions)
	Current Risk Management Assets			$	442		$	23		$	4		$	469		$	-344		$	125
	Long-term Risk Management Assets				342			5			-			347			-81			266
	Total Assets				784			28			4			816			-425			391

	Current Risk Management Liabilities				384			16			1			401			-341			60
	Long-term Risk Management Liabilities				205			4			13			222			-85			137
	Total Liabilities				589			20			14			623			-426			197

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	195		$	8		$	-10		$	193		$	1		$	194

	Fair Value of Derivative Instruments
	31-Dec-13

													Gross Amounts			Gross			Net Amounts of
				Risk Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in millions)
	Current Risk Management Assets			$	347		$	12		$	4		$	363		$	-203		$	160
	Long-term Risk Management Assets				368			3			-			371			-74			297
	Total Assets				715			15			4			734			-277			457

	Current Risk Management Liabilities				292			11			1			304			-214			90
	Long-term Risk Management Liabilities				237			3			15			255			-78			177
	Total Liabilities				529			14			16			559			-292			267

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	186		$	1		$	-12		$	175		$	15		$	190
	(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed 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." Amounts also include de-designated risk management contracts.
	(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain Loss Recognized on Risk Management Contracts	'
		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2014 and 2013

		Location of Gain (Loss)		2014				2013
				(in millions)
		Vertically Integrated Utilities Revenues		$	18		$	6
		Generation & Marketing Revenues			32			16
		Regulatory Assets (a)			-			2
		Regulatory Liabilities (a)			89			-6
		Total Gain on Risk Management Contracts		$	139		$	18
	(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'
		Impact of Cash Flow Hedges on the Condensed Balance Sheet
		31-Mar-14

									Interest Rate
									and Foreign
						Commodity			Currency			Total
						(in millions)
		Hedging Assets (a)				$	13		$	-		$	13
		Hedging Liabilities (a)					5			2			7
		AOCI Gain (Loss) Net of Tax					4			-22			-18
		Portion Expected to be Reclassified to Net
			Income During the Next Twelve Months				3			-4			-1

		Impact of Cash Flow Hedges on the Condensed Balance Sheet
		31-Dec-13

									Interest Rate
									and Foreign
						Commodity			Currency			Total
						(in millions)
		Hedging Assets (a)				$	7		$	-		$	7
		Hedging Liabilities (a)					6			2			8
		AOCI Gain (Loss) Net of Tax					-			-23			-23
		Portion Expected to be Reclassified to Net
			Income During the Next Twelve Months				-			-4			-4
	(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
Collateral Required Under Various Triggering Events	'
					March 31,			December 31,
					2014			2013
					(in millions)
		Liabilities for Derivative Contracts with Credit Downgrade Triggers			$	2		$	3
		Amount of Collateral AEP Subsidiaries Would Have Been
			Required to Post			144			33
		Amount Attributable to RTO and ISO Activities				38			28
Liabilities Subject to Cross Default Provisions	'
				March 31,			December 31,
				2014			2013
				(in millions)
		Liabilities for Contracts with Cross Default Provisions Prior to Contractual
		Netting Arrangements		$	225		$	293
		Amount of Cash Collateral Posted			-			1
		Additional Settlement Liability if Cross Default Provision is Triggered			177			235
Appalachian Power Co [Member]	'
Notional Volume of Derivative Instruments	'
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
Cash Collateral Netting	'
					31-Mar-14						31-Dec-13
					Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
					Received			Paid			Received			Paid
					Netted Against			Netted Against			Netted Against			Netted Against
					Risk Management			Risk Management			Risk Management			Risk Management
		Company			Assets			Liabilities			Assets			Liabilities
					(in thousands)
		APCo			$	32		$	1,362		$	-		$	2,993
		I&M				21			924			-			2,030
		OPCo				3			-			-			-
		PSO				1			-			-			1
		SWEPCo				2			-			-			3
Fair Value of Derivative Instruments	'
	APCo
	Fair Value of Derivative Instruments
	31-Mar-14

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	34,483		$	224		$	-		$	34,707		$	-18,735		$	15,972
	Long-term Risk Management Assets				17,304			-			-			17,304			-3,291			14,013
	Total Assets				51,787			224			-			52,011			-22,026			29,985

	Current Risk Management Liabilities				24,273			90			-			24,363			-19,727			4,636
	Long-term Risk Management Liabilities				11,558			-			-			11,558			-3,629			7,929
	Total Liabilities				35,831			90			-			35,921			-23,356			12,565

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	15,956		$	134		$	-		$	16,090		$	1,330		$	17,420

	APCo
	Fair Value of Derivative Instruments
	31-Dec-13

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	46,431		$	389		$	-		$	46,820		$	-25,649		$	21,171
	Long-term Risk Management Assets				20,948			-			-			20,948			-4,000			16,948
	Total Assets				67,379			389			-			67,768			-29,649			38,119

	Current Risk Management Liabilities				37,010			313			-			37,323			-28,431			8,892
	Long-term Risk Management Liabilities				14,452			-			-			14,452			-4,211			10,241
	Total Liabilities				51,462			313			-			51,775			-32,642			19,133

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	15,917		$	76		$	-		$	15,993		$	2,993		$	18,986
	(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
	(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
	(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain Loss Recognized on Risk Management Contracts	'
		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2014

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
		Sales to AEP Affiliates					-			-221			-			221			-
		Regulatory Assets (a)					4			-			-			2			3
		Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
		Total Gain on Risk Management
			Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2013

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
		Regulatory Assets (a)					-			486			-1,205			2,010			271
		Regulatory Liabilities (a)					-466			-5,182			-			1			96
		Total Gain on Risk Management
			Contracts			$	213		$	251		$	509		$	2,058		$	395

		(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
				or noncurrent on the condensed balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Mar-14

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
		I&M				142			-			51			-			61			-15,566
		OPCo				-			-			-			-			-			6,631
		PSO				-			-			-			-			-			5,512
		SWEPCo				-			-			-			-			-			-12,736
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
											Maximum Term for
								Interest Rate			Exposure to
								and Foreign			Variability of Future
		Company			Commodity			Currency			Cash Flows
					(in thousands)						(in months)
		APCo			$	87		$	-682			2
		I&M				61			-1,426			2
		OPCo				-			1,372			-
		PSO				-			759			-
		SWEPCo				-			-2,267			-
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Dec-13

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
		I&M				216			-			194			-			46			-15,976
		OPCo				162			-			-			-			105			6,974
		PSO				84			-			-			-			57			5,701
		SWEPCo				97			-			-			-			66			-13,304
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
								Interest Rate
								and Foreign
		Company			Commodity			Currency
					(in thousands)
		APCo			$	94		$	-806
		I&M				46			-1,568
		OPCo				105			1,363
		PSO				57			759
		SWEPCo				66			-2,267
	(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
Collateral Required Under Various Triggering Events	'
					31-Mar-14
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	285		$	5,254		$	4,774
		I&M				190			3,560			3,238
		OPCo				78			-			-
		PSO				132			4,156			-
		SWEPCo				167			145			-
					31-Dec-13
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	575		$	2,747		$	2,539
		I&M				390			1,863			1,722
		OPCo				349			-			-
		PSO				-			2,930			410
		SWEPCo				-			713			519
Liabilities Subject to Cross Default Provisions	'
					31-Mar-14
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	16,375		$	-		$	12,865
		I&M				11,107			-			8,726
		OPCo				-			-			-
		PSO				-			-			-
		SWEPCo				-			-			-

					31-Dec-13
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	19,648		$	-		$	18,568
		I&M				13,326			-			12,594
		OPCo				-			-			-
		PSO				3			-			3
		SWEPCo				3			-			3
Indiana Michigan Power Co [Member]	'
Notional Volume of Derivative Instruments	'
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
Cash Collateral Netting	'
					31-Mar-14						31-Dec-13
					Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
					Received			Paid			Received			Paid
					Netted Against			Netted Against			Netted Against			Netted Against
					Risk Management			Risk Management			Risk Management			Risk Management
		Company			Assets			Liabilities			Assets			Liabilities
					(in thousands)
		APCo			$	32		$	1,362		$	-		$	2,993
		I&M				21			924			-			2,030
		OPCo				3			-			-			-
		PSO				1			-			-			1
		SWEPCo				2			-			-			3
Fair Value of Derivative Instruments	'
	I&M
	Fair Value of Derivative Instruments
	31-Mar-14

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	26,273		$	152		$	-		$	26,425		$	-13,867		$	12,558
	Long-term Risk Management Assets				11,737			-			-			11,737			-2,232			9,505
	Total Assets				38,010			152			-			38,162			-16,099			22,063

	Current Risk Management Liabilities				18,614			61			-			18,675			-14,541			4,134
	Long-term Risk Management Liabilities				7,839			-			-			7,839			-2,461			5,378
	Total Liabilities				26,453			61			-			26,514			-17,002			9,512

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	11,557		$	91		$	-		$	11,648		$	903		$	12,551

	I&M
	Fair Value of Derivative Instruments
	31-Dec-13

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	33,229		$	234		$	-		$	33,463		$	-18,075		$	15,388
	Long-term Risk Management Assets				14,208			-			-			14,208			-2,713			11,495
	Total Assets				47,437			234			-			47,671			-20,788			26,883

	Current Risk Management Liabilities				26,779			212			-			26,991			-19,962			7,029
	Long-term Risk Management Liabilities				9,802			-			-			9,802			-2,856			6,946
	Total Liabilities				36,581			212			-			36,793			-22,818			13,975

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	10,856		$	22		$	-		$	10,878		$	2,030		$	12,908
	(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
	(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
	(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain Loss Recognized on Risk Management Contracts	'
		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2014

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
		Sales to AEP Affiliates					-			-221			-			221			-
		Regulatory Assets (a)					4			-			-			2			3
		Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
		Total Gain on Risk Management
			Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2013

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
		Regulatory Assets (a)					-			486			-1,205			2,010			271
		Regulatory Liabilities (a)					-466			-5,182			-			1			96
		Total Gain on Risk Management
			Contracts			$	213		$	251		$	509		$	2,058		$	395

		(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
				or noncurrent on the condensed balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Mar-14

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
		I&M				142			-			51			-			61			-15,566
		OPCo				-			-			-			-			-			6,631
		PSO				-			-			-			-			-			5,512
		SWEPCo				-			-			-			-			-			-12,736
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
											Maximum Term for
								Interest Rate			Exposure to
								and Foreign			Variability of Future
		Company			Commodity			Currency			Cash Flows
					(in thousands)						(in months)
		APCo			$	87		$	-682			2
		I&M				61			-1,426			2
		OPCo				-			1,372			-
		PSO				-			759			-
		SWEPCo				-			-2,267			-
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Dec-13

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
		I&M				216			-			194			-			46			-15,976
		OPCo				162			-			-			-			105			6,974
		PSO				84			-			-			-			57			5,701
		SWEPCo				97			-			-			-			66			-13,304
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
								Interest Rate
								and Foreign
		Company			Commodity			Currency
					(in thousands)
		APCo			$	94		$	-806
		I&M				46			-1,568
		OPCo				105			1,363
		PSO				57			759
		SWEPCo				66			-2,267
	(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
Collateral Required Under Various Triggering Events	'
					31-Mar-14
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	285		$	5,254		$	4,774
		I&M				190			3,560			3,238
		OPCo				78			-			-
		PSO				132			4,156			-
		SWEPCo				167			145			-
					31-Dec-13
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	575		$	2,747		$	2,539
		I&M				390			1,863			1,722
		OPCo				349			-			-
		PSO				-			2,930			410
		SWEPCo				-			713			519
Liabilities Subject to Cross Default Provisions	'
					31-Mar-14
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	16,375		$	-		$	12,865
		I&M				11,107			-			8,726
		OPCo				-			-			-
		PSO				-			-			-
		SWEPCo				-			-			-

					31-Dec-13
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	19,648		$	-		$	18,568
		I&M				13,326			-			12,594
		OPCo				-			-			-
		PSO				3			-			3
		SWEPCo				3			-			3
Ohio Power Co [Member]	'
Notional Volume of Derivative Instruments	'
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
Cash Collateral Netting	'
					31-Mar-14						31-Dec-13
					Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
					Received			Paid			Received			Paid
					Netted Against			Netted Against			Netted Against			Netted Against
					Risk Management			Risk Management			Risk Management			Risk Management
		Company			Assets			Liabilities			Assets			Liabilities
					(in thousands)
		APCo			$	32		$	1,362		$	-		$	2,993
		I&M				21			924			-			2,030
		OPCo				3			-			-			-
		PSO				1			-			-			1
		SWEPCo				2			-			-			3
Fair Value of Derivative Instruments	'
	OPCo
	Fair Value of Derivative Instruments
	31-Mar-14

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	4,066		$	-		$	-		$	4,066		$	-86		$	3,980
	Long-term Risk Management Assets				-			-			-			-			-			-
	Total Assets				4,066			-			-			4,066			-86			3,980

	Current Risk Management Liabilities				83			-			-			83			-83			-
	Long-term Risk Management Liabilities				-			-			-			-			-			-
	Total Liabilities				83			-			-			83			-83			-

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	3,983		$	-		$	-		$	3,983		$	-3		$	3,980

	OPCo
	Fair Value of Derivative Instruments
	31-Dec-13

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	3,269		$	162		$	-		$	3,431		$	-349		$	3,082
	Long-term Risk Management Assets				-			-			-			-			-			-
	Total Assets				3,269			162			-			3,431			-349			3,082

	Current Risk Management Liabilities				349			-			-			349			-349			-
	Long-term Risk Management Liabilities				-			-			-			-			-			-
	Total Liabilities				349			-			-			349			-349			-

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	2,920		$	162		$	-		$	3,082		$	-		$	3,082
	(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
	(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
	(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain Loss Recognized on Risk Management Contracts	'
		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2014

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
		Sales to AEP Affiliates					-			-221			-			221			-
		Regulatory Assets (a)					4			-			-			2			3
		Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
		Total Gain on Risk Management
			Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2013

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
		Regulatory Assets (a)					-			486			-1,205			2,010			271
		Regulatory Liabilities (a)					-466			-5,182			-			1			96
		Total Gain on Risk Management
			Contracts			$	213		$	251		$	509		$	2,058		$	395

		(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
				or noncurrent on the condensed balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Mar-14

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
		I&M				142			-			51			-			61			-15,566
		OPCo				-			-			-			-			-			6,631
		PSO				-			-			-			-			-			5,512
		SWEPCo				-			-			-			-			-			-12,736
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
											Maximum Term for
								Interest Rate			Exposure to
								and Foreign			Variability of Future
		Company			Commodity			Currency			Cash Flows
					(in thousands)						(in months)
		APCo			$	87		$	-682			2
		I&M				61			-1,426			2
		OPCo				-			1,372			-
		PSO				-			759			-
		SWEPCo				-			-2,267			-
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Dec-13

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
		I&M				216			-			194			-			46			-15,976
		OPCo				162			-			-			-			105			6,974
		PSO				84			-			-			-			57			5,701
		SWEPCo				97			-			-			-			66			-13,304
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
								Interest Rate
								and Foreign
		Company			Commodity			Currency
					(in thousands)
		APCo			$	94		$	-806
		I&M				46			-1,568
		OPCo				105			1,363
		PSO				57			759
		SWEPCo				66			-2,267
	(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
Collateral Required Under Various Triggering Events	'
					31-Mar-14
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	285		$	5,254		$	4,774
		I&M				190			3,560			3,238
		OPCo				78			-			-
		PSO				132			4,156			-
		SWEPCo				167			145			-
					31-Dec-13
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	575		$	2,747		$	2,539
		I&M				390			1,863			1,722
		OPCo				349			-			-
		PSO				-			2,930			410
		SWEPCo				-			713			519
Liabilities Subject to Cross Default Provisions	'
					31-Mar-14
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	16,375		$	-		$	12,865
		I&M				11,107			-			8,726
		OPCo				-			-			-
		PSO				-			-			-
		SWEPCo				-			-			-

					31-Dec-13
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	19,648		$	-		$	18,568
		I&M				13,326			-			12,594
		OPCo				-			-			-
		PSO				3			-			3
		SWEPCo				3			-			3
Public Service Co Of Oklahoma [Member]	'
Notional Volume of Derivative Instruments	'
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
Cash Collateral Netting	'
					31-Mar-14						31-Dec-13
					Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
					Received			Paid			Received			Paid
					Netted Against			Netted Against			Netted Against			Netted Against
					Risk Management			Risk Management			Risk Management			Risk Management
		Company			Assets			Liabilities			Assets			Liabilities
					(in thousands)
		APCo			$	32		$	1,362		$	-		$	2,993
		I&M				21			924			-			2,030
		OPCo				3			-			-			-
		PSO				1			-			-			1
		SWEPCo				2			-			-			3
Fair Value of Derivative Instruments	'
	PSO
	Fair Value of Derivative Instruments
	31-Mar-14

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	1,403		$	-		$	-		$	1,403		$	-54		$	1,349
	Long-term Risk Management Assets				-			-			-			-			-			-
	Total Assets				1,403			-			-			1,403			-54			1,349

	Current Risk Management Liabilities				136			-			-			136			-53			83
	Long-term Risk Management Liabilities				-			-			-			-			-			-
	Total Liabilities				136			-			-			136			-53			83

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	1,267		$	-		$	-		$	1,267		$	-1		$	1,266

	PSO
	Fair Value of Derivative Instruments
	31-Dec-13

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	1,078		$	84		$	-		$	1,162		$	5		$	1,167
	Long-term Risk Management Assets				-			-			-			-			-			-
	Total Assets				1,078			84			-			1,162			5			1,167

	Current Risk Management Liabilities				81			-			-			81			4			85
	Long-term Risk Management Liabilities				-			-			-			-			-			-
	Total Liabilities				81			-			-			81			4			85

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	997		$	84		$	-		$	1,081		$	1		$	1,082
	(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
	(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
	(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain Loss Recognized on Risk Management Contracts	'
		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2014

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
		Sales to AEP Affiliates					-			-221			-			221			-
		Regulatory Assets (a)					4			-			-			2			3
		Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
		Total Gain on Risk Management
			Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2013

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
		Regulatory Assets (a)					-			486			-1,205			2,010			271
		Regulatory Liabilities (a)					-466			-5,182			-			1			96
		Total Gain on Risk Management
			Contracts			$	213		$	251		$	509		$	2,058		$	395

		(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
				or noncurrent on the condensed balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Mar-14

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
		I&M				142			-			51			-			61			-15,566
		OPCo				-			-			-			-			-			6,631
		PSO				-			-			-			-			-			5,512
		SWEPCo				-			-			-			-			-			-12,736
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
											Maximum Term for
								Interest Rate			Exposure to
								and Foreign			Variability of Future
		Company			Commodity			Currency			Cash Flows
					(in thousands)						(in months)
		APCo			$	87		$	-682			2
		I&M				61			-1,426			2
		OPCo				-			1,372			-
		PSO				-			759			-
		SWEPCo				-			-2,267			-
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Dec-13

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
		I&M				216			-			194			-			46			-15,976
		OPCo				162			-			-			-			105			6,974
		PSO				84			-			-			-			57			5,701
		SWEPCo				97			-			-			-			66			-13,304
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
								Interest Rate
								and Foreign
		Company			Commodity			Currency
					(in thousands)
		APCo			$	94		$	-806
		I&M				46			-1,568
		OPCo				105			1,363
		PSO				57			759
		SWEPCo				66			-2,267
	(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
Collateral Required Under Various Triggering Events	'
					31-Mar-14
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	285		$	5,254		$	4,774
		I&M				190			3,560			3,238
		OPCo				78			-			-
		PSO				132			4,156			-
		SWEPCo				167			145			-
					31-Dec-13
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	575		$	2,747		$	2,539
		I&M				390			1,863			1,722
		OPCo				349			-			-
		PSO				-			2,930			410
		SWEPCo				-			713			519
Liabilities Subject to Cross Default Provisions	'
					31-Mar-14
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	16,375		$	-		$	12,865
		I&M				11,107			-			8,726
		OPCo				-			-			-
		PSO				-			-			-
		SWEPCo				-			-			-

					31-Dec-13
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	19,648		$	-		$	18,568
		I&M				13,326			-			12,594
		OPCo				-			-			-
		PSO				3			-			3
		SWEPCo				3			-			3
Southwestern Electric Power Co [Member]	'
Notional Volume of Derivative Instruments	'
	Notional Volume of Derivative Instruments
	31-Mar-14

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			29,680			19,636			12,108			9,251			11,716
		Coal			Tons			186			2,666			-			750			1,292
		Natural Gas			MMBtus			1,934			1,312			-			-			-
		Heating Oil and
			Gasoline		Gallons			792			379			806			446			508
		Interest Rate			USD		$	10,877		$	7,378		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-

	Notional Volume of Derivative Instruments
	31-Dec-13

	Primary Risk				Unit of
	Exposure				Measure		APCo			I&M			OPCo			PSO			SWEPCo
							(in thousands)
	Commodity:
		Power			MWhs			48,995			33,231			34,843			13,469			17,057
		Coal			Tons			31			3,389			-			1,013			1,692
		Natural Gas			MMBtus			2,477			1,680			-			-			-
		Heating Oil and
			Gasoline		Gallons			1,089			521			1,108			614			699
		Interest Rate			USD		$	12,720		$	8,627		$	-		$	-		$	-

	Interest Rate and
		Foreign Currency			USD		$	-		$	-		$	-		$	-		$	-
Cash Collateral Netting	'
					31-Mar-14						31-Dec-13
					Cash Collateral			Cash Collateral			Cash Collateral			Cash Collateral
					Received			Paid			Received			Paid
					Netted Against			Netted Against			Netted Against			Netted Against
					Risk Management			Risk Management			Risk Management			Risk Management
		Company			Assets			Liabilities			Assets			Liabilities
					(in thousands)
		APCo			$	32		$	1,362		$	-		$	2,993
		I&M				21			924			-			2,030
		OPCo				3			-			-			-
		PSO				1			-			-			1
		SWEPCo				2			-			-			3
Fair Value of Derivative Instruments	'
	SWEPCo
	Fair Value of Derivative Instruments
	31-Mar-14

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	2,080		$	-		$	-		$	2,080		$	-173		$	1,907
	Long-term Risk Management Assets				-			-			-			-			-			-
	Total Assets				2,080			-			-			2,080			-173			1,907

	Current Risk Management Liabilities				171			-			-			171			-171			-
	Long-term Risk Management Liabilities				-			-			-			-			-			-
	Total Liabilities				171			-			-			171			-171			-

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	1,909		$	-		$	-		$	1,909		$	-2		$	1,907

	SWEPCo
	Fair Value of Derivative Instruments
	31-Dec-13

				Risk									Gross Amounts			Gross			Net Amounts of
				Management									of Risk			Amounts			Assets/Liabilities
				Contracts			Hedging Contracts						Management			Offset in the			Presented in the
										Interest Rate			Assets/			Statement of			Statement of
										and Foreign			Liabilities			Financial			Financial
	Balance Sheet Location			Commodity (a)			Commodity (a)			Currency (a)			Recognized			Position (b)			Position (c)

				(in thousands)
	Current Risk Management Assets			$	1,233		$	97		$	-		$	1,330		$	-151		$	1,179
	Long-term Risk Management Assets				-			-			-			-			-			-
	Total Assets				1,233			97			-			1,330			-151			1,179

	Current Risk Management Liabilities				154			-			-			154			-154			-
	Long-term Risk Management Liabilities				-			-			-			-			-			-
	Total Liabilities				154			-			-			154			-154			-

	Total MTM Derivative Contract Net
		Assets (Liabilities)		$	1,079		$	97		$	-		$	1,176		$	3		$	1,179
	(a) Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
	(b) Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
	(c) There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
Amount of Gain Loss Recognized on Risk Management Contracts	'
		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2014

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	4,847		$	6,156		$	-		$	64		$	23
		Sales to AEP Affiliates					-			-221			-			221			-
		Regulatory Assets (a)					4			-			-			2			3
		Regulatory Liabilities (a)					32,332			18,317			35,099			480			1,330
		Total Gain on Risk Management
			Contracts			$	37,183		$	24,252		$	35,099		$	767		$	1,356

		Amount of Gain (Loss) Recognized on
		Risk Management Contracts
		For the Three Months Ended March 31, 2013

		Location of Gain (Loss)				APCo			I&M			OPCo			PSO			SWEPCo
						(in thousands)
		Electric Generation, Transmission and
			Distribution Revenues			$	679		$	4,947		$	1,714		$	47		$	28
		Regulatory Assets (a)					-			486			-1,205			2,010			271
		Regulatory Liabilities (a)					-466			-5,182			-			1			96
		Total Gain on Risk Management
			Contracts			$	213		$	251		$	509		$	2,058		$	395

		(a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current
				or noncurrent on the condensed balance sheets.
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Mar-14

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	209		$	-		$	75		$	-		$	87		$	3,343
		I&M				142			-			51			-			61			-15,566
		OPCo				-			-			-			-			-			6,631
		PSO				-			-			-			-			-			5,512
		SWEPCo				-			-			-			-			-			-12,736
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
											Maximum Term for
								Interest Rate			Exposure to
								and Foreign			Variability of Future
		Company			Commodity			Currency			Cash Flows
					(in thousands)						(in months)
		APCo			$	87		$	-682			2
		I&M				61			-1,426			2
		OPCo				-			1,372			-
		PSO				-			759			-
		SWEPCo				-			-2,267			-
		Impact of Cash Flow Hedges on the Registrant Subsidiaries’
		Condensed Balance Sheets
		31-Dec-13

					Hedging Assets (a)						Hedging Liabilities (a)						AOCI Gain (Loss) Net of Tax
								Interest Rate						Interest Rate						Interest Rate
								and Foreign						and Foreign						and Foreign
		Company			Commodity			Currency			Commodity			Currency			Commodity			Currency
					(in thousands)
		APCo			$	363		$	-		$	287		$	-		$	94		$	3,090
		I&M				216			-			194			-			46			-15,976
		OPCo				162			-			-			-			105			6,974
		PSO				84			-			-			-			57			5,701
		SWEPCo				97			-			-			-			66			-13,304
					Expected to be Reclassified to
					Net Income During the Next
					Twelve Months
								Interest Rate
								and Foreign
		Company			Commodity			Currency
					(in thousands)
		APCo			$	94		$	-806
		I&M				46			-1,568
		OPCo				105			1,363
		PSO				57			759
		SWEPCo				66			-2,267
	(a) Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
Collateral Required Under Various Triggering Events	'
					31-Mar-14
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	285		$	5,254		$	4,774
		I&M				190			3,560			3,238
		OPCo				78			-			-
		PSO				132			4,156			-
		SWEPCo				167			145			-
					31-Dec-13
					Liabilities for			Amount of Collateral the			Amount
					Derivative Contracts			Registrant Subsidiaries			Attributable to
					with Credit			Would Have Been			RTO and ISO
		Company			Downgrade Triggers			Required to Post			Activities
					(in thousands)
		APCo			$	575		$	2,747		$	2,539
		I&M				390			1,863			1,722
		OPCo				349			-			-
		PSO				-			2,930			410
		SWEPCo				-			713			519
Liabilities Subject to Cross Default Provisions	'
					31-Mar-14
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	16,375		$	-		$	12,865
		I&M				11,107			-			8,726
		OPCo				-			-			-
		PSO				-			-			-
		SWEPCo				-			-			-

					31-Dec-13
					Liabilities for						Additional
					Contracts with Cross						Settlement
					Default Provisions						Liability if Cross
					Prior to Contractual			Amount of Cash			Default Provision
		Company			Netting Arrangements			Collateral Posted			is Triggered
					(in thousands)
		APCo			$	19,648		$	-		$	18,568
		I&M				13,326			-			12,594
		OPCo				-			-			-
		PSO				3			-			3
		SWEPCo				3			-			3

Fair_Value_Measurements_Tables

Fair Value Measurements (Tables)	3 Months Ended
Fair Value Measurements (Tables)	Mar. 31, 2014
Book Values and Fair Values of Long-term Debt	'
				31-Mar-14						31-Dec-13
				Book Value			Fair Value			Book Value			Fair Value
				(in millions)
		Long-term Debt		$	18,087		$	19,738		$	18,377		$	19,672
Other Temporary Investments	'
						31-Mar-14
									Gross			Gross			Estimated
									Unrealized			Unrealized			Fair
		Other Temporary Investments				Cost			Gains			Losses			Value
						(in millions)
		Restricted Cash (a)				$	206		$	-		$	-		$	206
		Fixed Income Securities:
			Mutual Funds				80			-			-			80
		Equity Securities - Mutual Funds					13			11			-			24
		Total Other Temporary Investments				$	299		$	11		$	-		$	310

						31-Dec-13
									Gross			Gross			Estimated
									Unrealized			Unrealized			Fair
		Other Temporary Investments				Cost			Gains			Losses			Value
						(in millions)
		Restricted Cash (a)				$	250		$	-		$	-		$	250
		Fixed Income Securities:
			Mutual Funds				80			-			-			80
		Equity Securities - Mutual Funds					12			11			-			23
		Total Other Temporary Investments				$	342		$	11		$	-		$	353

		(a)		Primarily represents amounts held for the repayment of debt.
Debt and Equity Securities Within Other Temporary Investments	'
			Three Months Ended March 31,
			2014			2013
			(in millions)
		Proceeds from Investment Sales	$	-		$	-
		Purchases of Investments		1			11
		Gross Realized Gains on Investment Sales		-			-
		Gross Realized Losses on Investment Sales		-			-
Nuclear Trust Fund Investments	'
					31-Mar-14									31-Dec-13
					Estimated			Gross			Other-Than-			Estimated			Gross		Other-Than-
					Fair			Unrealized			Temporary			Fair			Unrealized		Temporary
					Value			Gains			Impairments			Value			Gains		Impairments
					(in millions)
		Cash and Cash Equivalents			$	12		$	-		$	-		$	19		$	-	$	-
		Fixed Income Securities:
			United States Government			606			31			-4			609			26		-4
			Corporate Debt			43			4			-1			37			2		-1
			State and Local Government			281			1			-			255			1		-
			Subtotal Fixed Income Securities			930			36			-5			901			29		-5
		Equity Securities - Domestic				1,020			514			-80			1,012			506		-82
		Spent Nuclear Fuel and
			Decommissioning Trusts		$	1,962		$	550		$	-85		$	1,932		$	535	$	-87
Securities Activity Within the Decommissioning and SNF Trusts	'
			Three Months Ended March 31,
			2014			2013
			(in millions)
		Proceeds from Investment Sales	$	148		$	168
		Purchases of Investments		164			185
		Gross Realized Gains on Investment Sales		8			3
		Gross Realized Losses on Investment Sales		1			2
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	'
			Fair Value of
			Fixed Income
			Securities
			(in millions)
		Within 1 year	$	82
		1 year – 5 years		386
		5 years – 10 years		193
		After 10 years		269
		Total	$	930
Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Mar-14

				Level 1			Level 2			Level 3			Other			Total

	Assets:			(in millions)

	Cash and Cash Equivalents (a)			$	16		$	1		$	-		$	275		$	292

	Other Temporary Investments
	Restricted Cash (a)				187			7			-			12			206
	Fixed Income Securities:
		Mutual Funds			80			-			-			-			80
	Equity Securities - Mutual Funds (b)				24			-			-			-			24
	Total Other Temporary Investments				291			7			-			12			310

	Risk Management Assets
	Risk Management Commodity Contracts (c) (d)				20			586			128			-364			370
	Cash Flow Hedges:
		Commodity Hedges (c)			-			21			2			-10			13
	Fair Value Hedges				-			2			-			2			4
	De-designated Risk Management Contracts (e)				-			-			-			4			4
	Total Risk Management Assets				20			609			130			-368			391

	Spent Nuclear Fuel and Decommissioning Trusts
	Cash and Cash Equivalents (f)				3			-			-			9			12
	Fixed Income Securities:
		United States Government			-			606			-			-			606
		Corporate Debt			-			43			-			-			43
		State and Local Government			-			281			-			-			281
			Subtotal Fixed Income Securities		-			930			-			-			930
	Equity Securities - Domestic (b)				1,020			-			-			-			1,020
	Total Spent Nuclear Fuel and Decommissioning Trusts				1,023			930			-			9			1,962

	Total Assets			$	1,350		$	1,547		$	130		$	-72		$	2,955

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (c) (d)			$	30		$	485		$	25		$	-362		$	178
	Cash Flow Hedges:
		Commodity Hedges (c)			-			15			-			-10			5
		Interest Rate/Foreign Currency Hedges			-			2			-			-			2
	Fair Value Hedges				-			10			-			2			12
	Total Risk Management Liabilities			$	30		$	512		$	25		$	-370		$	197
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Dec-13

				Level 1			Level 2			Level 3			Other			Total

	Assets:			(in millions)

	Cash and Cash Equivalents (a)			$	16		$	1		$	-		$	101		$	118

	Other Temporary Investments
	Restricted Cash (a)				231			8			-			11			250
	Fixed Income Securities:
		Mutual Funds			80			-			-			-			80
	Equity Securities - Mutual Funds (b)				23			-			-			-			23
	Total Other Temporary Investments				334			8			-			11			353

	Risk Management Assets
	Risk Management Commodity Contracts (c) (g)				22			549			142			-273			440
Cash Flow Hedges:
	Commodity Hedges (c)			-			15			-			-8			7
Fair Value Hedges				-			1			-			3			4
De-designated Risk Management Contracts (e)				-			-			-			6			6
Total Risk Management Assets				22			565			142			-272			457

Spent Nuclear Fuel and Decommissioning Trusts
Cash and Cash Equivalents (f)				8			-			-			11			19
Fixed Income Securities:
	United States Government			-			609			-			-			609
	Corporate Debt			-			37			-			-			37
	State and Local Government			-			255			-			-			255
		Subtotal Fixed Income Securities		-			901			-			-			901
Equity Securities - Domestic (b)				1,012			-			-			-			1,012
Total Spent Nuclear Fuel and Decommissioning Trusts				1,020			901			-			11			1,932

Total Assets			$	1,392		$	1,475		$	142		$	-149		$	2,860

Liabilities:

Risk Management Liabilities
Risk Management Commodity Contracts (c) (g)			$	30		$	475		$	22		$	-282		$	245
Cash Flow Hedges:
	Commodity Hedges (c)			-			11			3			-8			6
	Interest Rate/Foreign Currency Hedges			-			2			-			-			2
Fair Value Hedges				-			11			-			3			14
Total Risk Management Liabilities			$	30		$	499		$	25		$	-287		$	267
(a) Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
(b) Amounts represent publicly traded equity securities and equity-based mutual funds.
(c) Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''
(d) The March 31, 2014 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 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.
(e) Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.'' At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts.
(f) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(g) The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.
Changes in Fair Value of Net Trading Derivatives and Other Investments	'
					Net Risk Management
		Three Months Ended March 31, 2014			Assets (Liabilities)
					(in millions)
		Balance as of December 31, 2013			$	117
		Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)				84
		Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
			Relating to Assets Still Held at the Reporting Date (a)			-10
		Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income				9
		Purchases, Issuances and Settlements (c)				-100
		Transfers into Level 3 (d) (e)				-4
		Transfers out of Level 3 (e) (f)				-2
		Changes in Fair Value Allocated to Regulated Jurisdictions (g)				11
		Balance as of March 31, 2014			$	105
					Net Risk Management
		Three Months Ended March 31, 2013			Assets (Liabilities)
					(in millions)
		Balance as of December 31, 2012			$	86
		Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b)				-4
		Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets)
			Relating to Assets Still Held at the Reporting Date (a)			-5
		Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income				1
		Purchases, Issuances and Settlements (c)				-6
		Transfers into Level 3 (d) (e)				6
		Transfers out of Level 3 (e) (f)				-
		Changes in Fair Value Allocated to Regulated Jurisdictions (g)				-2
		Balance as of March 31, 2013			$	76
	(a) Included in revenues on the condensed statements of income.
	(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
	(c) Represents the settlement of risk management commodity contracts for the reporting period.
	(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) Represents existing assets or liabilities that were previously categorized as Level 3.
	(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
Significant Unobservable Inputs for Level 3	'
	Significant Unobservable Inputs
	31-Mar-14

			Fair Value						Valuation		Significant		Input/Range
			Assets			Liabilities			Technique		Unobservable Input		Low			High
			(in millions)
	Energy Contracts		$	116		$	23		Discounted Cash Flow		Forward Market Price (a)		$	1.45		$	131.46
											Counterparty Credit Risk (b)			315
	FTRs			14			2		Discounted Cash Flow		Forward Market Price (a)			-5.05			9.17
	Total		$	130		$	25
	Significant Unobservable Inputs
	31-Dec-13

			Fair Value						Valuation		Significant		Input/Range
			Assets			Liabilities			Technique		Unobservable Input		Low			High
			(in millions)
	Energy Contracts		$	132		$	22		Discounted Cash Flow		Forward Market Price (a)		$	11.42		$	120.72
											Counterparty Credit Risk (b)			316
	FTRs			10			3		Discounted Cash Flow		Forward Market Price (a)			-5.1			10.44
	Total		$	142		$	25
	(a) Represents market prices in dollars per MWh.
	(b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Appalachian Power Co [Member]	'
Book Values and Fair Values of Long-term Debt	'
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	APCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Restricted Cash for Securitized Funding (a)		$	13,536		$	-		$	-		$	36		$	13,572

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			393			37,854			10,508			-18,979			29,776
	Cash Flow Hedges:
		Commodity Hedges (b)		-			224			-			-15			209
	Total Risk Management Assets			393			38,078			10,508			-18,994			29,985

	Total Assets:		$	13,929		$	38,078		$	10,508		$	-18,958		$	43,557

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	306		$	29,386		$	3,107		$	-20,309		$	12,490
	Cash Flow Hedges:
		Commodity Hedges (b)		-			90			-			-15			75
	Total Risk Management Liabilities		$	306		$	29,476		$	3,107		$	-20,324		$	12,565
	APCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Restricted Cash for Securitized Funding (a)		$	2,714		$	-		$	-		$	36		$	2,750

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			827			54,448			12,097			-29,616			37,756
	Cash Flow Hedges:
		Commodity Hedges (b)		-			389			-			-26			363
	Total Risk Management Assets			827			54,837			12,097			-29,642			38,119

	Total Assets		$	3,541		$	54,837		$	12,097		$	-29,606		$	40,869

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	700		$	49,220		$	1,535		$	-32,609		$	18,846
	Cash Flow Hedges:
		Commodity Hedges (b)		-			313			-			-26			287
	Total Risk Management Liabilities		$	700		$	49,533		$	1,535		$	-32,635		$	19,133
	(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
	(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
	(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
	(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
	(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
Changes in Fair Value of Net Trading Derivatives and Other Investments	'
		Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
		Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
		Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			3,289			2,052			4,065			349			442
		Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
		Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				257			179			366			-			-
		Transfers into Level 3 (d) (e)				632			434			888			-			-
		Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			-1,123			-732			490			-			-
		Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
	(a) Included in revenues on the condensed statements of income.
	(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
	(c) Represents the settlement of risk management commodity contracts for the reporting period.
	(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) Represents existing assets or liabilities that were previously categorized as Level 3.
	(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
Significant Unobservable Inputs for Level 3	'
		Significant Unobservable Inputs
		31-Mar-14
		APCo
				Fair Value						Valuation		Significant		Forward Price Range
				Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
				(in thousands)
		Energy Contracts		$	6,454		$	2,822		Discounted Cash Flow		Forward Market Price		$	13.34		$	59.6
		FTRs			4,054			285		Discounted Cash Flow		Forward Market Price			-5.05			9.17
		Total		$	10,508		$	3,107

		Significant Unobservable Inputs
		31-Dec-13
		APCo
				Fair Value						Valuation		Significant		Forward Price Range
				Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
				(in thousands)
		Energy Contracts		$	9,359		$	960		Discounted Cash Flow		Forward Market Price		$	13.04		$	80.5
		FTRs			2,738			575		Discounted Cash Flow		Forward Market Price			-5.1			10.44
		Total		$	12,097		$	1,535
	(a) Represents market prices in dollars per MWh.
Indiana Michigan Power Co [Member]	'
Book Values and Fair Values of Long-term Debt	'
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
Nuclear Trust Fund Investments	'
					31-Mar-14									31-Dec-13
					Estimated			Gross			Other-Than-			Estimated			Gross		Other-Than-
					Fair			Unrealized			Temporary			Fair			Unrealized		Temporary
					Value			Gains			Impairments			Value			Gains		Impairments
					(in thousands)
		Cash and Cash Equivalents			$	12,439		$	-		$	-		$	18,804		$	-	$	-
		Fixed Income Securities:
			United States Government			606,228			31,666			-3,621			608,875			26,114		-3,824
			Corporate Debt			42,727			3,223			-1,097			36,782			2,450		-1,123
			State and Local Government			280,612			972			-345			254,638			748		-370
			Subtotal Fixed Income Securities			929,567			35,861			-5,063			900,295			29,312		-5,317
		Equity Securities - Domestic				1,020,145			513,803			-79,563			1,012,511			505,538		-81,677
		Spent Nuclear Fuel and
			Decommissioning Trusts		$	1,962,151		$	549,664		$	-84,626		$	1,931,610		$	534,850	$	-86,994
Securities Activity Within the Decommissioning and SNF Trusts	'
			Three Months Ended March 31,
			2014			2013
			(in thousands)
		Proceeds from Investment Sales	$	147,700		$	167,670
		Purchases of Investments		164,511			184,299
		Gross Realized Gains on Investment Sales		8,141			3,323
		Gross Realized Losses on Investment Sales		874			2,315
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	'
			Fair Value of
			Fixed Income
			Securities

			(in thousands)
		Within 1 year	$	82,190
		1 year – 5 years		386,173
		5 years – 10 years		193,018
		After 10 years		268,186
		Total	$	929,567
Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	I&M
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Mar-14

				Level 1			Level 2			Level 3			Other			Total

	Assets:			(in thousands)

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			$	267		$	28,746		$	6,945		$	-14,037		$	21,921
	Cash Flow Hedges:
		Commodity Hedges (b)			-			152			-			-10			142
	Total Risk Management Assets				267			28,898			6,945			-14,047			22,063

	Spent Nuclear Fuel and Decommissioning Trusts
	Cash and Cash Equivalents (d)				3,576			-			-			8,863			12,439
	Fixed Income Securities:
		United States Government			-			606,228			-			-			606,228
		Corporate Debt			-			42,727			-			-			42,727
		State and Local Government			-			280,612			-			-			280,612
			Subtotal Fixed Income Securities		-			929,567			-			-			929,567
	Equity Securities - Domestic (e)				1,020,145			-			-			-			1,020,145
	Total Spent Nuclear Fuel and Decommissioning Trusts				1,023,721			929,567			-			8,863			1,962,151

	Total Assets			$	1,023,988		$	958,465		$	6,945		$	-5,184		$	1,984,214

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)			$	208		$	22,089		$	2,104		$	-14,940		$	9,461
	Cash Flow Hedges:
		Commodity Hedges (b)			-			61			-			-10			51
	Total Risk Management Liabilities			$	208		$	22,150		$	2,104		$	-14,950		$	9,512
	I&M
			Assets and Liabilities Measured at Fair Value on a Recurring Basis
			31-Dec-13

				Level 1			Level 2			Level 3			Other			Total

	Assets:			(in thousands)

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			$	561		$	38,667		$	8,205		$	-20,766		$	26,667
	Cash Flow Hedges:
		Commodity Hedges (b)			-			234			-			-18			216
	Total Risk Management Assets				561			38,901			8,205			-20,784			26,883

	Spent Nuclear Fuel and Decommissioning Trusts
	Cash and Cash Equivalents (d)				8,082			-			-			10,722			18,804
	Fixed Income Securities:
		United States Government			-			608,875			-			-			608,875
		Corporate Debt			-			36,782			-			-			36,782
		State and Local Government			-			254,638			-			-			254,638
			Subtotal Fixed Income Securities		-			900,295			-			-			900,295
	Equity Securities - Domestic (e)				1,012,511			-			-			-			1,012,511
	Total Spent Nuclear Fuel and Decommissioning Trusts				1,020,593			900,295			-			10,722			1,931,610

	Total Assets			$	1,021,154		$	939,196		$	8,205		$	-10,062		$	1,958,493

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)			$	475		$	35,061		$	1,041		$	-22,796		$	13,781
Cash Flow Hedges:
	Commodity Hedges (b)			-			212			-			-18			194
Total Risk Management Liabilities			$	475		$	35,273		$	1,041		$	-22,814		$	13,975
(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
Changes in Fair Value of Net Trading Derivatives and Other Investments	'
		Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
		Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
		Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			3,289			2,052			4,065			349			442
		Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
		Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				257			179			366			-			-
		Transfers into Level 3 (d) (e)				632			434			888			-			-
		Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			-1,123			-732			490			-			-
		Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
	(a) Included in revenues on the condensed statements of income.
	(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
	(c) Represents the settlement of risk management commodity contracts for the reporting period.
	(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) Represents existing assets or liabilities that were previously categorized as Level 3.
	(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
Significant Unobservable Inputs for Level 3	'
		Significant Unobservable Inputs
		31-Mar-14
		I&M
				Fair Value						Valuation		Significant		Forward Price Range
				Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
				(in thousands)
		Energy Contracts		$	4,378		$	1,914		Discounted Cash Flow		Forward Market Price		$	13.34		$	59.6
		FTRs			2,567			190		Discounted Cash Flow		Forward Market Price			-5.05			9.17
		Total		$	6,945		$	2,104

		Significant Unobservable Inputs
		31-Dec-13
		I&M
				Fair Value						Valuation		Significant		Forward Price Range
				Assets			Liabilities			Technique		Unobservable Input (a)		Low			High

				(in thousands)
		Energy Contracts		$	6,348		$	651		Discounted Cash Flow		Forward Market Price		$	13.04		$	80.5
		FTRs			1,857			390		Discounted Cash Flow		Forward Market Price			-5.1			10.44
		Total		$	8,205		$	1,041
	(a) Represents market prices in dollars per MWh.
Ohio Power Co [Member]	'
Book Values and Fair Values of Long-term Debt	'
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	OPCo
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Restricted Cash for Securitized Funding (a)		$	32,054		$	-		$	-		$	12		$	32,066

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			-			76			3,990			-86			3,980

	Total Assets		$	32,054		$	76		$	3,990		$	-74		$	36,046

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	5		$	78		$	-83		$	-
	OPCo
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Restricted Cash for Securitized Funding (a)		$	19,387		$	-		$	-		$	12		$	19,399

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			-			-			3,269			-349			2,920
	Cash Flow Hedges:
		Commodity Hedges (b)		-			162			-			-			162
	Total Risk Management Assets			-			162			3,269			-349			3,082

	Total Assets		$	19,387		$	162		$	3,269		$	-337		$	22,481

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	-		$	349		$	-349		$	-
	(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
	(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
	(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
	(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
	(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
Changes in Fair Value of Net Trading Derivatives and Other Investments	'
		Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
		Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
		Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			3,289			2,052			4,065			349			442
		Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
		Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				257			179			366			-			-
		Transfers into Level 3 (d) (e)				632			434			888			-			-
		Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			-1,123			-732			490			-			-
		Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
	(a) Included in revenues on the condensed statements of income.
	(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
	(c) Represents the settlement of risk management commodity contracts for the reporting period.
	(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) Represents existing assets or liabilities that were previously categorized as Level 3.
	(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
Significant Unobservable Inputs for Level 3	'
		Significant Unobservable Inputs
		31-Mar-14
		OPCo
				Fair Value						Valuation		Significant		Forward Price Range
				Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
				(in thousands)
		Energy Contracts		$	-		$	-		Discounted Cash Flow		Forward Market Price		$	-		$	-
		FTRs			3,990			78		Discounted Cash Flow		Forward Market Price			-5.05			9.17
		Total		$	3,990		$	78

		Significant Unobservable Inputs
		31-Dec-13
		OPCo
				Fair Value						Valuation		Significant		Forward Price Range
				Assets			Liabilities			Technique		Unobservable Input (a)		Low			High

				(in thousands)
		Energy Contracts		$	-		$	-		Discounted Cash Flow		Forward Market Price		$	-		$	-
		FTRs			3,269			349		Discounted Cash Flow		Forward Market Price			-5.1			10.44
		Total		$	3,269		$	349
	(a) Represents market prices in dollars per MWh.
Public Service Co Of Oklahoma [Member]	'
Book Values and Fair Values of Long-term Debt	'
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	PSO
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)		$	-		$	922		$	481		$	-54		$	1,349

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	4		$	132		$	-53		$	83
	PSO
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)		$	-		$	1,078		$	-		$	5		$	1,083
	Cash Flow Hedges:
		Commodity Hedges (b)		-			84			-			-			84
	Total Risk Management Assets		$	-		$	1,162		$	-		$	5		$	1,167

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	81		$	-		$	4		$	85
	(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
	(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
	(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
	(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
	(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
Changes in Fair Value of Net Trading Derivatives and Other Investments	'
		Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
		Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
		Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			3,289			2,052			4,065			349			442
		Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
		Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				257			179			366			-			-
		Transfers into Level 3 (d) (e)				632			434			888			-			-
		Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			-1,123			-732			490			-			-
		Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
	(a) Included in revenues on the condensed statements of income.
	(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
	(c) Represents the settlement of risk management commodity contracts for the reporting period.
	(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) Represents existing assets or liabilities that were previously categorized as Level 3.
	(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
Significant Unobservable Inputs for Level 3	'
		Significant Unobservable Inputs
		31-Mar-14
		PSO
				Fair Value						Valuation		Significant		Forward Price Range
				Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
				(in thousands)
		Energy Contracts		$	-		$	-		Discounted Cash Flow		Forward Market Price		$	-		$	-
		FTRs			481			132		Discounted Cash Flow		Forward Market Price			-5.05			9.17
		Total		$	481		$	132
	(a) Represents market prices in dollars per MWh.
Southwestern Electric Power Co [Member]	'
Book Values and Fair Values of Long-term Debt	'
				31-Mar-14						31-Dec-13
		Company		Book Value			Fair Value			Book Value			Fair Value
				(in thousands)
		APCo		$	4,194,516		$	4,730,819		$	4,194,357		$	4,587,079
		I&M			2,012,844			2,203,640			2,039,016			2,174,891
		OPCo			2,510,285			2,869,364			2,735,175			3,007,191
		PSO			1,049,793			1,200,741			999,810			1,111,149
		SWEPCo			2,041,796			2,277,262			2,043,332			2,214,730
Fair Value, Assets and Liabilities Measured on Recurring Basis	'
	SWEPCo
	Assets and Liabilities Measured at Fair Value on a Recurring Basis
	31-Mar-14

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Cash and Cash Equivalents (a)		$	15,537		$	-		$	-		$	2,458		$	17,995

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			-			1,471			609			-173			1,907

	Total Assets		$	15,537		$	1,471		$	609		$	2,285		$	19,902

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	4		$	167		$	-171		$	-
	SWEPCo
		Assets and Liabilities Measured at Fair Value on a Recurring Basis
		31-Dec-13

			Level 1			Level 2			Level 3			Other			Total

	Assets:		(in thousands)

	Cash and Cash Equivalents (a)		$	15,871		$	-		$	-		$	1,370		$	17,241

	Risk Management Assets
	Risk Management Commodity Contracts (b) (c)			-			1,233			-			-151			1,082
	Cash Flow Hedges:
		Commodity Hedges (b)		-			97			-			-			97
	Total Risk Management Assets			-			1,330			-			-151			1,179

	Total Assets		$	15,871		$	1,330		$	-		$	1,219		$	18,420

	Liabilities:

	Risk Management Liabilities
	Risk Management Commodity Contracts (b) (c)		$	-		$	154		$	-		$	-154		$	-
	(a) Amounts in “Other” column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investment in money market funds.
	(b) Amounts in “Other” column primarily represent counterparty netting of risk management and hedging contracts associated cash collateral under the accounting guidance for “Derivatives and Hedging”.
	(c) Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
	(d) Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
	(e) Amounts represent publicly traded equity securities and equity-based mutual funds.
Changes in Fair Value of Net Trading Derivatives and Other Investments	'
		Three Months Ended March 31, 2014			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2013			$	10,562		$	7,164		$	2,920		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			29,162			18,219			30,963			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				-31,781			-19,995			-34,036			-			-
		Transfers into Level 3 (d) (e)				-3,825			-2,594			-			-			-
		Transfers out of Level 3 (e) (f)				-6			-4			-			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			3,289			2,052			4,065			349			442
		Balance as of March 31, 2014			$	7,401		$	4,842		$	3,912		$	349		$	442
		Three Months Ended March 31, 2013			APCo			I&M			OPCo			PSO			SWEPCo
					(in thousands)
		Balance as of December 31, 2012			$	10,979		$	7,541		$	15,429		$	-		$	-
		Realized Gain (Loss) Included in Net Income
			(or Changes in Net Assets) (a) (b)			-1,456			-1,005			-2,055			-			-
		Unrealized Gain (Loss) Included in Net
			Income (or Changes in Net Assets) Relating
			to Assets Still Held at the Reporting Date (a)			-			-			-1,988			-			-
		Realized and Unrealized Gains (Losses)
			Included in Other Comprehensive Income			-			-			-			-			-
		Purchases, Issuances and Settlements (c)				257			179			366			-			-
		Transfers into Level 3 (d) (e)				632			434			888			-			-
		Transfers out of Level 3 (e) (f)				-533			-366			-749			-			-
		Changes in Fair Value Allocated to Regulated
			Jurisdictions (g)			-1,123			-732			490			-			-
		Balance as of March 31, 2013			$	8,756		$	6,051		$	12,381		$	-		$	-
	(a) Included in revenues on the condensed statements of income.
	(b) Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
	(c) Represents the settlement of risk management commodity contracts for the reporting period.
	(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) Represents existing assets or liabilities that were previously categorized as Level 3.
	(g) Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
Significant Unobservable Inputs for Level 3	'
		Significant Unobservable Inputs
		31-Mar-14
		SWEPCo
				Fair Value						Valuation		Significant		Forward Price Range
				Assets			Liabilities			Technique		Unobservable Input (a)		Low			High
				(in thousands)
		Energy Contracts		$	-		$	-		Discounted Cash Flow		Forward Market Price		$	-		$	-
		FTRs			609			167		Discounted Cash Flow		Forward Market Price			-5.05			9.17
		Total		$	609		$	167
	(a) Represents market prices in dollars per MWh.

Financing_Activities_Tables

Financing Activities (Tables)	3 Months Ended
Financing Activities (Tables)	Mar. 31, 2014
Long-term Debt	'
		Type of Debt		31-Mar-14			31-Dec-13
				(in millions)
		Senior Unsecured Notes		$	11,571		$	11,799
		Pollution Control Bonds			1,932			1,932
		Notes Payable			342			369
		Securitization Bonds			2,574			2,686
		Spent Nuclear Fuel Obligation (a)			265			265
		Other Long-term Debt			1,434			1,360
		Fair Value of Interest Rate Hedges			-7			-9
		Unamortized Discount, Net			-24			-25
		Total Long-term Debt Outstanding			18,087			18,377
		Long-term Debt Due Within One Year			1,612			1,549
		Long-term Debt		$	16,475		$	16,828
	(a) Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of March 31, 2014 and December 31, 2013, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

Long-term Debt Issuances	'
							Principal				Interest
		Company			Type of Debt		Amount				Rate		Due Date
		Issuances:				(in millions)					(%)
		PSO			Other Long-term Debt		$	50			Variable		2016

		Non-Registrant:
		Transource Missouri			Other Long-term Debt			27			Variable		2018
		Total Issuances					$	77	(a)
	(a) Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances.
Retirements and Principal Payments	'
							Principal				Interest
		Company			Type of Debt		Amount Paid				Rate		Due Date
		Retirements and				(in millions)					(%)
			Principal Payments:
		I&M			Notes Payable		$	5			Variable		2016
		I&M			Notes Payable			4			2.12		2016
		I&M			Notes Payable			5			Variable		2016
		I&M			Notes Payable			10			Variable		2017
		I&M			Other Long-term Debt			2			Variable		2015
		OPCo			Senior Unsecured Notes			225			4.85		2014
		SWEPCo			Notes Payable			2			4.58		2032

		Non-Registrant:
		AEGCo			Senior Unsecured Notes			4			6.33		2037
		AEP Subsidiaries			Notes Payable			1			Variable		2017
		TCC			Securitization Bonds			72			5.09		2015
		TCC			Securitization Bonds			40			6.25		2016
		Total Retirements and
			Principal Payments				$	370
Short Term Debt	'
					31-Mar-14						31-Dec-13
					Outstanding			Interest			Outstanding			Interest
		Type of Debt			Amount			Rate (a)			Amount			Rate (a)
					(in millions)						(in millions)
		Securitized Debt for Receivables (b)			$	700		0.24	%		$	700		0.23	%
		Commercial Paper				632		0.31	%			57		0.29	%
		Total Short-term Debt			$	1,332					$	757
	(a) Weighted average rate.
	(b) Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.

Comparative Accounts Receivable Information	'
					Three Months Ended
					March 31,
					2014			2013
					(dollars in millions)
		Effective Interest Rates on Securitization of Accounts Receivable				0.24	%		0.23	%
		Net Uncollectible Accounts Receivable Written Off			$	8		$	7
Customer Accounts Receivable Managed Portfolio	'
					March 31,			December 31,
					2014			2013
					(in millions)
		Accounts Receivable Retained Interest and Pledged as Collateral
			Less Uncollectible Accounts		$	997		$	929
		Total Principal Outstanding				700			700
		Delinquent Securitized Accounts Receivable				55			45
		Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable				17			16
		Unbilled Receivables Related to Securitization/Sale of Accounts Receivable				278			331
Appalachian Power Co [Member]	'
Long-term Debt Issuances	'
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	'
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	'
																Net
																Loans to
				Maximum			Maximum			Average			Average			(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans			the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility			Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool			31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681		$	245,516	$	600,000
		I&M			-			158,857			-			92,303			59,162		500,000
		OPCo			55,640			405,350			25,930			135,747			-27,108		600,000
		PSO			121,100			-			58,500			-			-70,119		300,000
		SWEPCo			130,258			-			61,132			-			-117,342		350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	'
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	'
				Average Interest Rate						Average Interest Rate
				for Funds Borrowed						for Funds Loaned
				from the Utility Money Pool for						to the Utility Money Pool for
				Three Months Ended March 31,						Three Months Ended March 31,
		Company		2014			2013			2014			2013
		APCo		-	%		0.38	%		0.31	%		0.37	%
		I&M		-	%		0.36	%		0.31	%		0.37	%
		OPCo		0.31	%		0.36	%		0.29	%		0.37	%
		PSO		0.31	%		0.36	%		-	%		0.38	%
		SWEPCo		0.31	%		-	%		-	%		0.38	%
Accounts Receivable and Accrued Unbilled Revenues	'
					March 31,			December 31,
		Company			2014			2013
					(in thousands)
		APCo			$	175,738		$	156,599
		I&M				154,510			139,257
		OPCo				350,735			324,287
		PSO				111,522			115,260
		SWEPCo				145,648			149,337
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	2,423		$	1,556
		I&M				2,040			1,452
		OPCo				7,498			4,669
		PSO				1,323			1,414
		SWEPCo				1,566			1,380
Proceeds on Sale of Receivables to AEP Credit	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	437,196		$	398,193
		I&M				407,150			351,830
		OPCo				686,627			696,958
		PSO				290,217			240,275
		SWEPCo				390,588			331,936
Indiana Michigan Power Co [Member]	'
Long-term Debt Issuances	'
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	'
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	'
																Net
																Loans to
				Maximum			Maximum			Average			Average			(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans			the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility			Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool			31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681		$	245,516	$	600,000
		I&M			-			158,857			-			92,303			59,162		500,000
		OPCo			55,640			405,350			25,930			135,747			-27,108		600,000
		PSO			121,100			-			58,500			-			-70,119		300,000
		SWEPCo			130,258			-			61,132			-			-117,342		350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	'
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	'
				Average Interest Rate						Average Interest Rate
				for Funds Borrowed						for Funds Loaned
				from the Utility Money Pool for						to the Utility Money Pool for
				Three Months Ended March 31,						Three Months Ended March 31,
		Company		2014			2013			2014			2013
		APCo		-	%		0.38	%		0.31	%		0.37	%
		I&M		-	%		0.36	%		0.31	%		0.37	%
		OPCo		0.31	%		0.36	%		0.29	%		0.37	%
		PSO		0.31	%		0.36	%		-	%		0.38	%
		SWEPCo		0.31	%		-	%		-	%		0.38	%
Accounts Receivable and Accrued Unbilled Revenues	'
					March 31,			December 31,
		Company			2014			2013
					(in thousands)
		APCo			$	175,738		$	156,599
		I&M				154,510			139,257
		OPCo				350,735			324,287
		PSO				111,522			115,260
		SWEPCo				145,648			149,337
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	2,423		$	1,556
		I&M				2,040			1,452
		OPCo				7,498			4,669
		PSO				1,323			1,414
		SWEPCo				1,566			1,380
Proceeds on Sale of Receivables to AEP Credit	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	437,196		$	398,193
		I&M				407,150			351,830
		OPCo				686,627			696,958
		PSO				290,217			240,275
		SWEPCo				390,588			331,936
Ohio Power Co [Member]	'
Long-term Debt Issuances	'
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	'
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	'
																Net
																Loans to
				Maximum			Maximum			Average			Average			(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans			the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility			Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool			31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681		$	245,516	$	600,000
		I&M			-			158,857			-			92,303			59,162		500,000
		OPCo			55,640			405,350			25,930			135,747			-27,108		600,000
		PSO			121,100			-			58,500			-			-70,119		300,000
		SWEPCo			130,258			-			61,132			-			-117,342		350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	'
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	'
				Average Interest Rate						Average Interest Rate
				for Funds Borrowed						for Funds Loaned
				from the Utility Money Pool for						to the Utility Money Pool for
				Three Months Ended March 31,						Three Months Ended March 31,
		Company		2014			2013			2014			2013
		APCo		-	%		0.38	%		0.31	%		0.37	%
		I&M		-	%		0.36	%		0.31	%		0.37	%
		OPCo		0.31	%		0.36	%		0.29	%		0.37	%
		PSO		0.31	%		0.36	%		-	%		0.38	%
		SWEPCo		0.31	%		-	%		-	%		0.38	%
Accounts Receivable and Accrued Unbilled Revenues	'
					March 31,			December 31,
		Company			2014			2013
					(in thousands)
		APCo			$	175,738		$	156,599
		I&M				154,510			139,257
		OPCo				350,735			324,287
		PSO				111,522			115,260
		SWEPCo				145,648			149,337
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	2,423		$	1,556
		I&M				2,040			1,452
		OPCo				7,498			4,669
		PSO				1,323			1,414
		SWEPCo				1,566			1,380
Proceeds on Sale of Receivables to AEP Credit	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	437,196		$	398,193
		I&M				407,150			351,830
		OPCo				686,627			696,958
		PSO				290,217			240,275
		SWEPCo				390,588			331,936
Public Service Co Of Oklahoma [Member]	'
Long-term Debt Issuances	'
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

Retirements and Principal Payments	'
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	'
																Net
																Loans to
				Maximum			Maximum			Average			Average			(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans			the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility			Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool			31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681		$	245,516	$	600,000
		I&M			-			158,857			-			92,303			59,162		500,000
		OPCo			55,640			405,350			25,930			135,747			-27,108		600,000
		PSO			121,100			-			58,500			-			-70,119		300,000
		SWEPCo			130,258			-			61,132			-			-117,342		350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	'
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	'
				Average Interest Rate						Average Interest Rate
				for Funds Borrowed						for Funds Loaned
				from the Utility Money Pool for						to the Utility Money Pool for
				Three Months Ended March 31,						Three Months Ended March 31,
		Company		2014			2013			2014			2013
		APCo		-	%		0.38	%		0.31	%		0.37	%
		I&M		-	%		0.36	%		0.31	%		0.37	%
		OPCo		0.31	%		0.36	%		0.29	%		0.37	%
		PSO		0.31	%		0.36	%		-	%		0.38	%
		SWEPCo		0.31	%		-	%		-	%		0.38	%
Accounts Receivable and Accrued Unbilled Revenues	'
					March 31,			December 31,
		Company			2014			2013
					(in thousands)
		APCo			$	175,738		$	156,599
		I&M				154,510			139,257
		OPCo				350,735			324,287
		PSO				111,522			115,260
		SWEPCo				145,648			149,337
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	2,423		$	1,556
		I&M				2,040			1,452
		OPCo				7,498			4,669
		PSO				1,323			1,414
		SWEPCo				1,566			1,380
Proceeds on Sale of Receivables to AEP Credit	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	437,196		$	398,193
		I&M				407,150			351,830
		OPCo				686,627			696,958
		PSO				290,217			240,275
		SWEPCo				390,588			331,936
Southwestern Electric Power Co [Member]	'
Long-term Debt Issuances	'
						Principal			Interest
		Company		Type of Debt		Amount (a)			Rate		Due Date
		Issuances:				(in thousands)			(%)
		PSO		Other Long-term Debt		$	50,000		Variable		2016
	(a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.

Retirements and Principal Payments	'
							Principal			Interest
		Company			Type of Debt		Amount Paid			Rate		Due Date
		Retirements and					(in thousands)			(%)
			Principal Payments:
		APCo			Land Note		$	8		13.718		2026
		I&M			Notes Payable			9,866		Variable		2017
		I&M			Notes Payable			5,324		Variable		2016
		I&M			Notes Payable			5,214		Variable		2016
		I&M			Notes Payable			3,611		2.12		2016
		I&M			Other Long-term Debt			2,063		Variable		2015
		I&M			Other Long-term Debt			259		6		2025
		OPCo			Other Long-term Debt			29		1.149		2028
		OPCo			Senior Unsecured Notes			225,000		4.85		2014
		PSO			Other Long-term Debt			102		3		2027
		SWEPCo			Notes Payable			1,625		4.58		2032
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	'
																Net
																Loans to
				Maximum			Maximum			Average			Average			(Borrowings from)		Authorized
				Borrowings			Loans			Borrowings			Loans			the Utility		Short-term
				from the Utility			to the Utility			from the Utility			to the Utility			Money Pool as of		Borrowing
		Company		Money Pool			Money Pool			Money Pool			Money Pool			31-Mar-14		Limit
				(in thousands)
		APCo		$	-		$	249,630		$	-		$	164,681		$	245,516	$	600,000
		I&M			-			158,857			-			92,303			59,162		500,000
		OPCo			55,640			405,350			25,930			135,747			-27,108		600,000
		PSO			121,100			-			58,500			-			-70,119		300,000
		SWEPCo			130,258			-			61,132			-			-117,342		350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	'
				Three Months Ended March 31,
				2014			2013
		Maximum Interest Rate		0.33	%		0.43	%
		Minimum Interest Rate		0.28	%		0.35	%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	'
				Average Interest Rate						Average Interest Rate
				for Funds Borrowed						for Funds Loaned
				from the Utility Money Pool for						to the Utility Money Pool for
				Three Months Ended March 31,						Three Months Ended March 31,
		Company		2014			2013			2014			2013
		APCo		-	%		0.38	%		0.31	%		0.37	%
		I&M		-	%		0.36	%		0.31	%		0.37	%
		OPCo		0.31	%		0.36	%		0.29	%		0.37	%
		PSO		0.31	%		0.36	%		-	%		0.38	%
		SWEPCo		0.31	%		-	%		-	%		0.38	%
Accounts Receivable and Accrued Unbilled Revenues	'
					March 31,			December 31,
		Company			2014			2013
					(in thousands)
		APCo			$	175,738		$	156,599
		I&M				154,510			139,257
		OPCo				350,735			324,287
		PSO				111,522			115,260
		SWEPCo				145,648			149,337
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	2,423		$	1,556
		I&M				2,040			1,452
		OPCo				7,498			4,669
		PSO				1,323			1,414
		SWEPCo				1,566			1,380
Proceeds on Sale of Receivables to AEP Credit	'
					Three Months Ended March 31,
		Company			2014			2013
					(in thousands)
		APCo			$	437,196		$	398,193
		I&M				407,150			351,830
		OPCo				686,627			696,958
		PSO				290,217			240,275
		SWEPCo				390,588			331,936

Variable_Interest_Entities_Tab

Variable Interest Entities (Tables)	3 Months Ended
Variable Interest Entities (Tables)	Mar. 31, 2014
Consolidated Assets and Liabilities of Variable Interest Entities	'
	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
	VARIABLE INTEREST ENTITIES
	31-Mar-14
	(in millions)

																			APCo
																OPCo			Appalachian
																Ohio			Consumer
													TCC			Phase-in-			Rate			Protected
				SWEPCo			I&M			AEP			Transition			Recovery			Relief			Cell		Transource
				Sabine			DCC Fuel			Credit			Funding			Funding			Funding			of EIS		Energy
	ASSETS
	Current Assets			$	62		$	109		$	1,004		$	166		$	36		$	16		$	152	$	4
	Net Property, Plant and
		Equipment			154			129			-			-			-			-			-		57
	Other Noncurrent Assets				50			45			-			1,861	(a)		242	(b)		374	(c)		3		5
	Total Assets			$	266		$	283		$	1,004		$	2,027		$	278		$	390		$	155	$	66

	LIABILITIES AND EQUITY
	Current Liabilities			$	29		$	100		$	894		$	304		$	60		$	28		$	48	$	18
	Noncurrent Liabilities				236			183			1			1,705			217			360			67		28
	Equity				1			-			109			18			1			2			40		20
	Total Liabilities and Equity			$	266		$	283		$	1,004		$	2,027		$	278		$	390		$	155	$	66
	(a) Includes an intercompany item eliminated in consolidation of $81 million.
	(b) Includes an intercompany item eliminated in consolidation of $112 million.
	(c) Includes an intercompany item eliminated in consolidation of $4 million.
	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES
	VARIABLE INTEREST ENTITIES
	31-Dec-13
	(in millions)

																		APCo
															OPCo			Appalachian
															Ohio			Consumer
												TCC			Phase-in-			Rate
			SWEPCo			I&M			AEP			Transition			Recovery			Relief			Protected Cell
			Sabine			DCC Fuel			Credit			Funding			Funding			Funding			of EIS
	ASSETS
	Current Assets		$	67		$	118		$	935		$	232		$	23		$	6		$	143
	Net Property, Plant and Equipment			157			157			-			-			-			-			-
	Other Noncurrent Assets			51			60			1			1,918	(a)		252	(b)		378	(c)		3
	Total Assets		$	275		$	335		$	936		$	2,150		$	275		$	384		$	146

	LIABILITIES AND EQUITY
	Current Liabilities		$	33		$	108		$	827		$	312		$	37		$	14		$	39
	Noncurrent Liabilities			242			227			1			1,820			237			368			66
	Equity			-			-			108			18			1			2			41
	Total Liabilities and Equity		$	275		$	335		$	936		$	2,150		$	275		$	384		$	146
	(a) Includes an intercompany item eliminated in consolidation of $82 million.
	(b) Includes an intercompany item eliminated in consolidation of $116 million.
	(c) Includes an intercompany item eliminated in consolidation of $4 million.

Appalachian Power Co [Member]	'
Billings from Significant Variable Interest	'

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
Appalachian Power Co [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'
Carrying Amount and Classification of Variable Interest in Accounts Payable	'

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
Appalachian Power Co [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'
Consolidated Assets and Liabilities of Variable Interest Entities	'
		APPALACHIAN POWER COMPANY AND SUBSIDIARIES
		VARIABLE INTEREST ENTITIES
		March 31, 2014 and December 31, 2013
		(in thousands)
				Appalachian Consumer
				Rate Relief Funding
		ASSETS		2014			2013
		Current Assets		$	15,981		$	5,891
		Other Noncurrent Assets (a)			373,521			378,029
		Total Assets		$	389,502		$	383,920

		LIABILITIES AND EQUITY
		Current Liabilities		$	27,682		$	14,000
		Noncurrent Liabilities			359,919			368,018
		Equity			1,901			1,902
		Total Liabilities and Equity		$	389,502		$	383,920
	(a) Includes an intercompany item eliminated in consolidation as of March 31, 2014 of and December 31, 2013 of $4 million and $4 million, respectively.
Indiana Michigan Power Co [Member]	'
Billings from Significant Variable Interest	'

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
Indiana Michigan Power Co [Member] \| Billings from AEP Generating Co [Member]	'
Billings from Significant Variable Interest	'

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		I&M		$	70,422		$	58,535
		OPCo			-			38,711
Indiana Michigan Power Co [Member] \| Carrying Amount in AEGCo's Accounts Payable [Member]	'
Carrying Amount and Classification of Variable Interest in Accounts Payable	'
				31-Mar-14						31-Dec-13
				As Reported on			Maximum			As Reported on			Maximum
		Company		the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in thousands)
		I&M		$	24,364		$	24,364		$	23,916		$	23,916
		OPCo			-			-			12,810			12,810
Indiana Michigan Power Co [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'
Carrying Amount and Classification of Variable Interest in Accounts Payable	'

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
Indiana Michigan Power Co [Member] \| DCC Fuel [Member]	'
Consolidated Assets and Liabilities of Variable Interest Entities	'
		INDIANA MICHIGAN POWER COMPANY AND SUBSIDIARIES
		VARIABLE INTEREST ENTITIES
		March 31, 2014 and December 31, 2013
		(in thousands)
				DCC Fuel
		ASSETS		2014			2013
		Current Assets		$	109,374		$	117,762
		Net Property, Plant and Equipment			129,013			156,820
		Other Noncurrent Assets			44,853			60,450
		Total Assets		$	283,240		$	335,032

		LIABILITIES AND EQUITY
		Current Liabilities		$	100,141		$	107,815
		Noncurrent Liabilities			183,099			227,217
		Total Liabilities and Equity		$	283,240		$	335,032
Ohio Power Co [Member]	'
Billings from Significant Variable Interest	'

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
Ohio Power Co [Member] \| Billings from AEP Generating Co [Member]	'
Billings from Significant Variable Interest	'

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		I&M		$	70,422		$	58,535
		OPCo			-			38,711
Ohio Power Co [Member] \| Carrying Amount in AEGCo's Accounts Payable [Member]	'
Carrying Amount and Classification of Variable Interest in Accounts Payable	'
				31-Mar-14						31-Dec-13
				As Reported on			Maximum			As Reported on			Maximum
		Company		the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in thousands)
		I&M		$	24,364		$	24,364		$	23,916		$	23,916
		OPCo			-			-			12,810			12,810
Ohio Power Co [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'
Carrying Amount and Classification of Variable Interest in Accounts Payable	'

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
Ohio Power Co [Member] \| Ohio Phase-In-Recovery Funding [Member]	'
Consolidated Assets and Liabilities of Variable Interest Entities	'
		OHIO POWER COMPANY AND SUBSIDIARIES
		VARIABLE INTEREST ENTITIES
		March 31, 2014 and December 31, 2013
		(in thousands)
				Ohio Phase-in-
				Recovery Funding
		ASSETS		2014			2013
		Current Assets		$	35,958		$	23,198
		Other Noncurrent Assets (a)			241,814			251,409
		Total Assets		$	277,772		$	274,607

		LIABILITIES AND EQUITY
		Current Liabilities		$	59,590		$	36,470
		Noncurrent Liabilities			216,845			236,800
		Equity			1,337			1,337
		Total Liabilities and Equity		$	277,772		$	274,607
	(a) Includes an intercompany item eliminated in consolidation as of March 31, 2014 and December 31, 2013 of $112 million and $116 million, respectively.
Public Service Co Of Oklahoma [Member]	'
Billings from Significant Variable Interest	'

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
Public Service Co Of Oklahoma [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'
Carrying Amount and Classification of Variable Interest in Accounts Payable	'

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
Southwestern Electric Power Co [Member]	'
Billings from Significant Variable Interest	'

				Three Months Ended March 31,
		Company		2014			2013
				(in thousands)
		APCo		$	50,136		$	39,040
		I&M			31,969			27,498
		OPCo			39,049			54,069
		PSO			24,439			18,161
		SWEPCo			33,023			27,480
Southwestern Electric Power Co [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'
Carrying Amount and Classification of Variable Interest in Accounts Payable	'

				31-Mar-14						31-Dec-13
				As Reported on the			Maximum			As Reported on the			Maximum
		Company		Balance Sheet			Exposure			Balance Sheet			Exposure
				(in thousands)
		APCo		$	19,304		$	19,304		$	20,191		$	20,191
		I&M			12,040			12,040			12,864			12,864
		OPCo			14,046			14,046			31,425			31,425
		PSO			9,330			9,330			10,596			10,596
		SWEPCo			12,833			12,833			13,520			13,520
Southwestern Electric Power Co [Member] \| Sabine Mining Co [Member]	'
Consolidated Assets and Liabilities of Variable Interest Entities	'
		SOUTHWESTERN ELECTRIC POWER COMPANY CONSOLIDATED
		VARIABLE INTEREST ENTITIES
		March 31, 2014 and December 31, 2013
		(in thousands)
				Sabine
		ASSETS		2014			2013
		Current Assets		$	61,675		$	66,478
		Net Property, Plant and Equipment			153,928			157,274
		Other Noncurrent Assets			50,140			51,211
		Total Assets		$	265,743		$	274,963

		LIABILITIES AND EQUITY
		Current Liabilities		$	29,257		$	32,812
		Noncurrent Liabilities			236,142			241,673
		Equity			344			478
		Total Liabilities and Equity		$	265,743		$	274,963
Southwestern Electric Power Co [Member] \| Dolet Hills Lignite Co, LLC [Member]	'
Companys Investment In Joint Venture	'
				31-Mar-14						31-Dec-13
				As Reported on			Maximum			As Reported on			Maximum
				the Balance Sheet			Exposure			the Balance Sheet			Exposure
				(in thousands)
		Capital Contribution from SWEPCo		$	7,643		$	7,643		$	7,643		$	7,643
		Retained Earnings			1,910			1,910			1,600			1,600
		SWEPCo's Guarantee of Debt			-			85,190			-			61,348

		Total Investment in DHLC		$	9,553		$	94,743		$	9,243		$	70,591
PATH West Virginia Transmission Co, LLC [Member]	'
Companys Investment In Joint Venture	'
			31-Mar-14						31-Dec-13
			As Reported on			Maximum			As Reported on			Maximum
			the Balance Sheet			Exposure			the Balance Sheet			Exposure
					(in millions)
		Capital Contribution from AEP	$	19		$	19		$	19		$	19
		Retained Earnings		6			6			6			6

		Total Investment in PATH-WV	$	25		$	25		$	25		$	25

Significant_Accounting_Matters3

Significant Accounting Matters (Details) (USD $)	3 Months Ended
In Thousands, except Share data, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Basic and Diluted EPS Calculations	'	'
Earnings Attributable to AEP Common Shareholders	$560,000	$363,000
Weighted Average Number of Basic AEP Common Shares Outstanding	487,867,089	485,823,668
Total Basic Earnings Per Share Attributable to AEP Common Shareholders	$1.15	$0.75
Weighted Average Dilutive Effect of:	'	'
Weighted Average Number of Diluted AEP Common Shares Outstanding	488,271,167	486,344,036
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders	$1.15	$0.75
Amounts Attributable to AEP Common Shareholders	'	'
Net Income	560,000	363,000
Organization and Summary of Significant Accounting Policies (Textuals) [Abstract]	'	'
Antidilutive Shares Outstanding	0	0
Southwestern Electric Power Co [Member]	'	'
Basic and Diluted EPS Calculations	'	'
Earnings Attributable to AEP Common Shareholders	21,860	10,458
Amounts Attributable to AEP Common Shareholders	'	'
Net Income	$21,860	$10,458
Employee Stock Option [Member]	'	'
Weighted Average Dilutive Effect of:	'	'
Weighted Average Dilutive Effect of Shares	0	0
Dilutive Securities, Effect on Basic Earnings Per Share	$0	$0
Restricted Stock Units [Member]	'	'
Weighted Average Dilutive Effect of:	'	'
Weighted Average Dilutive Effect of Shares	400,000	500,000
Dilutive Securities, Effect on Basic Earnings Per Share	$0	$0

Comprehensive_Income_Details

Comprehensive Income (Details) (USD $)	3 Months Ended
Comprehensive Income (Details) (USD $)	Mar. 31, 2014		Mar. 31, 2013
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	($115,000,000)		($337,000,000)
Change in Fair Value Recognized in AOCI	-14,000,000		22,000,000
Amounts Reclassified from AOCI	20,000,000		9,000,000
Net Current Period Other Comprehensive Income	6,000,000		31,000,000
Ending Balance in AOCI	-109,000,000		-306,000,000
Commodity	'		'
Vertically Integrated Utilities Revenues	2,549,000,000		2,356,000,000
Generation & Marketing Revenues	117,000,000		122,000,000
Purchased Electricity for Resale	638,000,000		371,000,000
Other Operation Expense	780,000,000		738,000,000
Maintenance Expense	292,000,000		293,000,000
Interest Rate and Foreign Currency	'		'
Depreciation and Amortization Expense	491,000,000		420,000,000
Interest Expense	220,000,000		232,000,000
Income Tax (Expense) Credit	-307,000,000		-195,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	20,000,000		9,000,000
Gains and Losses on Securities Available for Sale	'		'
Interest and Investment Income	1,000,000		3,000,000
Interest Expense	220,000,000		232,000,000
Income Tax (Expense) Credit	-307,000,000		-195,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	20,000,000		9,000,000
Pension and OPEB	'		'
Income Tax (Expense) Credit	-307,000,000		-195,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	20,000,000		9,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	20,000,000		9,000,000
Securities Available for Sale [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	7,000,000		4,000,000
Change in Fair Value Recognized in AOCI	0		1,000,000
Amounts Reclassified from AOCI	0		0
Net Current Period Other Comprehensive Income	0		1,000,000
Ending Balance in AOCI	7,000,000		5,000,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		0
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		0
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		0
Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	-99,000,000		-303,000,000
Change in Fair Value Recognized in AOCI	0		0
Amounts Reclassified from AOCI	1,000,000		6,000,000
Net Current Period Other Comprehensive Income	1,000,000		6,000,000
Ending Balance in AOCI	-98,000,000		-297,000,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		6,000,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		6,000,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		6,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		6,000,000
Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	0		-8,000,000
Change in Fair Value Recognized in AOCI	-14,000,000		18,000,000
Amounts Reclassified from AOCI	18,000,000		2,000,000
Net Current Period Other Comprehensive Income	4,000,000		20,000,000
Ending Balance in AOCI	4,000,000		12,000,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	18,000,000		2,000,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	18,000,000		2,000,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	18,000,000		2,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	18,000,000		2,000,000
Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	-23,000,000		-30,000,000
Change in Fair Value Recognized in AOCI	0		3,000,000
Amounts Reclassified from AOCI	1,000,000		1,000,000
Net Current Period Other Comprehensive Income	1,000,000		4,000,000
Ending Balance in AOCI	-22,000,000		-26,000,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		1,000,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		1,000,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		1,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		1,000,000
Reclassifications from Accumulated Other Comprehensive Income [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	20,000,000		9,000,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	20,000,000		9,000,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	20,000,000		9,000,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	20,000,000		9,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	20,000,000		9,000,000
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	19,000,000		3,000,000
Commodity	'		'
Subtotal - Commodity	30,000,000		5,000,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	30,000,000		5,000,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	30,000,000		5,000,000
Income Tax (Expense) Credit	11,000,000		2,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	19,000,000		3,000,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	30,000,000		5,000,000
Income Tax (Expense) Credit	11,000,000		2,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	19,000,000		3,000,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	30,000,000		5,000,000
Income Tax (Expense) Credit	11,000,000		2,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	19,000,000		3,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	19,000,000		3,000,000
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Securities Available for Sale [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	0		0
Commodity	'		'
Subtotal - Commodity	0		0
Interest Rate and Foreign Currency	'		'
Interest Expense	0		0
Subtotal - Interest Rate and Foreign Currency	0		0
Reclassifications from AOCI, before Income Tax (Expense) Credit	0		0
Income Tax (Expense) Credit	0		0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		0
Gains and Losses on Securities Available for Sale	'		'
Interest and Investment Income	0		0
Interest Expense	0		0
Reclassifications from AOCI, before Income Tax (Expense) Credit	0		0
Income Tax (Expense) Credit	0		0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		0
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	0		0
Income Tax (Expense) Credit	0		0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		0
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	1,000,000		6,000,000
Commodity	'		'
Subtotal - Commodity	2,000,000		9,000,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	2,000,000		9,000,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	2,000,000		9,000,000
Income Tax (Expense) Credit	1,000,000		3,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		6,000,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	2,000,000		9,000,000
Income Tax (Expense) Credit	1,000,000		3,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		6,000,000
Pension and OPEB	'		'
Amortization of Prior Service Cost (Credit)	-5,000,000		-5,000,000
Amortization of Actuarial (Gains)/Losses	7,000,000		14,000,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	2,000,000		9,000,000
Income Tax (Expense) Credit	1,000,000		3,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		6,000,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	1,000,000		6,000,000
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Vertically Integrated Utilities Revenues	0		0
Generation & Marketing Revenues	0		-3,000,000
Purchased Electricity for Resale	31,000,000		6,000,000
Property, Plant and Equipment	0		0
Regulatory Assets/(Liabilities), Net	-3,000,000	[1]	0	[1]
Subtotal - Commodity	28,000,000		3,000,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	28,000,000		3,000,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	28,000,000		3,000,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	28,000,000		3,000,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	28,000,000		3,000,000
Reclassifications from Accumulated Other Comprehensive Income [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Subtotal - Commodity	2,000,000		2,000,000
Interest Rate and Foreign Currency	'		'
Interest Expense	2,000,000		2,000,000
Subtotal - Interest Rate and Foreign Currency	2,000,000		2,000,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	2,000,000		2,000,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	2,000,000		2,000,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	2,000,000		2,000,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	2,000,000		2,000,000
Appalachian Power Co [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	2,951,000		-29,898,000
Change in Fair Value Recognized in AOCI	1,583,000		793,000
Amounts Reclassified from AOCI	-1,670,000		823,000
Net Current Period Other Comprehensive Income	-87,000		1,616,000
Ending Balance in AOCI	2,864,000		-28,282,000
Commodity	'		'
Vertically Integrated Utilities Revenues	866,457,000		872,732,000
Generation & Marketing Revenues	2,020,000		1,902,000
Purchased Electricity for Resale	168,991,000		65,456,000
Other Operation Expense	93,538,000		78,908,000
Maintenance Expense	60,090,000		99,386,000
Interest Rate and Foreign Currency	'		'
Depreciation and Amortization Expense	104,586,000		87,903,000
Interest Expense	51,672,000		48,204,000
Income Tax (Expense) Credit	-66,248,000		-47,012,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,670,000		823,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	51,672,000		48,204,000
Income Tax (Expense) Credit	-66,248,000		-47,012,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,670,000		823,000
Pension and OPEB	'		'
Income Tax (Expense) Credit	-66,248,000		-47,012,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,670,000		823,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,670,000		823,000
Appalachian Power Co [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	-233,000		-31,331,000
Change in Fair Value Recognized in AOCI	0		0
Amounts Reclassified from AOCI	-333,000		358,000
Net Current Period Other Comprehensive Income	-333,000		358,000
Ending Balance in AOCI	-566,000		-30,973,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-333,000		358,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-333,000		358,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-333,000		358,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-333,000		358,000
Appalachian Power Co [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	94,000		-644,000
Change in Fair Value Recognized in AOCI	1,583,000		794,000
Amounts Reclassified from AOCI	-1,590,000		211,000
Net Current Period Other Comprehensive Income	-7,000		1,005,000
Ending Balance in AOCI	87,000		361,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,590,000		211,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,590,000		211,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,590,000		211,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,590,000		211,000
Appalachian Power Co [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	3,090,000		2,077,000
Change in Fair Value Recognized in AOCI	0		-1,000
Amounts Reclassified from AOCI	253,000		254,000
Net Current Period Other Comprehensive Income	253,000		253,000
Ending Balance in AOCI	3,343,000		2,330,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	253,000		254,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	253,000		254,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	253,000		254,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	253,000		254,000
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-1,670,000		823,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,670,000		823,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,670,000		823,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,670,000		823,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,670,000		823,000
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-1,337,000		465,000
Commodity	'		'
Subtotal - Commodity	-2,056,000		715,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-2,056,000		715,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-2,056,000		715,000
Income Tax (Expense) Credit	-719,000		250,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,337,000		465,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-2,056,000		715,000
Income Tax (Expense) Credit	-719,000		250,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,337,000		465,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-2,056,000		715,000
Income Tax (Expense) Credit	-719,000		250,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,337,000		465,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,337,000		465,000
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-333,000		358,000
Commodity	'		'
Subtotal - Commodity	-512,000		551,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-512,000		551,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-512,000		551,000
Income Tax (Expense) Credit	-179,000		193,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-333,000		358,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-512,000		551,000
Income Tax (Expense) Credit	-179,000		193,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-333,000		358,000
Pension and OPEB	'		'
Amortization of Prior Service Cost (Credit)	-1,282,000		-1,282,000
Amortization of Actuarial (Gains)/Losses	770,000		1,833,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-512,000		551,000
Income Tax (Expense) Credit	-179,000		193,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-333,000		358,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-333,000		358,000
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Vertically Integrated Utilities Revenues	0		20,000
Purchased Electricity for Resale	-462,000		57,000
Other Operation Expense	-10,000		-11,000
Maintenance Expense	-20,000		-16,000
Property, Plant and Equipment	-17,000		-14,000
Regulatory Assets/(Liabilities), Net	-1,937,000	[1]	289,000	[1]
Subtotal - Commodity	-2,446,000		325,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-2,446,000		325,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-2,446,000		325,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-2,446,000		325,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-2,446,000		325,000
Appalachian Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Subtotal - Commodity	390,000		390,000
Interest Rate and Foreign Currency	'		'
Interest Expense	390,000		390,000
Subtotal - Interest Rate and Foreign Currency	390,000		390,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	390,000		390,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	390,000		390,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	390,000		390,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	390,000		390,000
Indiana Michigan Power Co [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	-15,509,000		-28,883,000
Change in Fair Value Recognized in AOCI	1,062,000		2,781,000
Amounts Reclassified from AOCI	-594,000		518,000
Net Current Period Other Comprehensive Income	468,000		3,299,000
Ending Balance in AOCI	-15,041,000		-25,584,000
Commodity	'		'
Vertically Integrated Utilities Revenues	614,843,000		490,603,000
Generation & Marketing Revenues	0		1,988,000
Purchased Electricity for Resale	5,362,000		41,812,000
Other Operation Expense	141,350,000		145,238,000
Maintenance Expense	48,565,000		45,514,000
Interest Rate and Foreign Currency	'		'
Depreciation and Amortization Expense	50,031,000		40,902,000
Interest Expense	25,633,000		24,211,000
Income Tax (Expense) Credit	-38,315,000		-21,263,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-594,000		518,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	25,633,000		24,211,000
Income Tax (Expense) Credit	-38,315,000		-21,263,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-594,000		518,000
Pension and OPEB	'		'
Income Tax (Expense) Credit	-38,315,000		-21,263,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-594,000		518,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-594,000		518,000
Indiana Michigan Power Co [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	421,000		-8,790,000
Change in Fair Value Recognized in AOCI	0		0
Amounts Reclassified from AOCI	43,000		176,000
Net Current Period Other Comprehensive Income	43,000		176,000
Ending Balance in AOCI	464,000		-8,614,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	43,000		176,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	43,000		176,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	43,000		176,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	43,000		176,000
Indiana Michigan Power Co [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	46,000		-446,000
Change in Fair Value Recognized in AOCI	1,062,000		532,000
Amounts Reclassified from AOCI	-1,047,000		150,000
Net Current Period Other Comprehensive Income	15,000		682,000
Ending Balance in AOCI	61,000		236,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,047,000		150,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,047,000		150,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,047,000		150,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-1,047,000		150,000
Indiana Michigan Power Co [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	-15,976,000		-19,647,000
Change in Fair Value Recognized in AOCI	0		2,249,000
Amounts Reclassified from AOCI	410,000		192,000
Net Current Period Other Comprehensive Income	410,000		2,441,000
Ending Balance in AOCI	-15,566,000		-17,206,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	410,000		192,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	410,000		192,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	410,000		192,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	410,000		192,000
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-594,000		518,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-594,000		518,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-594,000		518,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-594,000		518,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-594,000		518,000
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-637,000		342,000
Commodity	'		'
Subtotal - Commodity	-980,000		526,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-980,000		526,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-980,000		526,000
Income Tax (Expense) Credit	-343,000		184,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-637,000		342,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-980,000		526,000
Income Tax (Expense) Credit	-343,000		184,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-637,000		342,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-980,000		526,000
Income Tax (Expense) Credit	-343,000		184,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-637,000		342,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-637,000		342,000
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	43,000		176,000
Commodity	'		'
Subtotal - Commodity	66,000		270,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	66,000		270,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	66,000		270,000
Income Tax (Expense) Credit	23,000		94,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	43,000		176,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	66,000		270,000
Income Tax (Expense) Credit	23,000		94,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	43,000		176,000
Pension and OPEB	'		'
Amortization of Prior Service Cost (Credit)	-199,000		-199,000
Amortization of Actuarial (Gains)/Losses	265,000		469,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	66,000		270,000
Income Tax (Expense) Credit	23,000		94,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	43,000		176,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	43,000		176,000
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Vertically Integrated Utilities Revenues	0		52,000
Purchased Electricity for Resale	-717,000		149,000
Other Operation Expense	-7,000		-7,000
Maintenance Expense	-7,000		-7,000
Property, Plant and Equipment	-10,000		-7,000
Regulatory Assets/(Liabilities), Net	-870,000	[1]	50,000	[1]
Subtotal - Commodity	-1,611,000		230,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-1,611,000		230,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-1,611,000		230,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-1,611,000		230,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-1,611,000		230,000
Indiana Michigan Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Subtotal - Commodity	631,000		296,000
Interest Rate and Foreign Currency	'		'
Interest Expense	631,000		296,000
Subtotal - Interest Rate and Foreign Currency	631,000		296,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	631,000		296,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	631,000		296,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	631,000		296,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	631,000		296,000
Ohio Power Co [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	7,079,000		-165,725,000
Change in Fair Value Recognized in AOCI	0		1,102,000
Amounts Reclassified from AOCI	-448,000		3,233,000
Net Current Period Other Comprehensive Income	-448,000		4,335,000
Ending Balance in AOCI	6,631,000		-161,390,000
Commodity	'		'
Generation & Marketing Revenues	1,308,000		6,627,000
Purchased Electricity for Resale	79,130,000		43,185,000
Other Operation Expense	151,426,000		184,187,000
Maintenance Expense	34,651,000		74,295,000
Interest Rate and Foreign Currency	'		'
Depreciation and Amortization Expense	58,699,000		92,324,000
Interest Expense	33,007,000		50,173,000
Income Tax (Expense) Credit	-34,052,000		-69,796,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		3,233,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	33,007,000		50,173,000
Income Tax (Expense) Credit	-34,052,000		-69,796,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		3,233,000
Pension and OPEB	'		'
Income Tax (Expense) Credit	-34,052,000		-69,796,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		3,233,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		3,233,000
Ohio Power Co [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	0		-172,908,000
Change in Fair Value Recognized in AOCI	0		0
Amounts Reclassified from AOCI	0		3,269,000
Net Current Period Other Comprehensive Income	0		3,269,000
Ending Balance in AOCI	0		-169,639,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		3,269,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		3,269,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		3,269,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		3,269,000
Ohio Power Co [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	105,000		-912,000
Change in Fair Value Recognized in AOCI	0		1,102,000
Amounts Reclassified from AOCI	-105,000		304,000
Net Current Period Other Comprehensive Income	-105,000		1,406,000
Ending Balance in AOCI	0		494,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-105,000		304,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-105,000		304,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-105,000		304,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-105,000		304,000
Ohio Power Co [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	6,974,000		8,095,000
Change in Fair Value Recognized in AOCI	0		0
Amounts Reclassified from AOCI	-343,000		-340,000
Net Current Period Other Comprehensive Income	-343,000		-340,000
Ending Balance in AOCI	6,631,000		7,755,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-343,000		-340,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-343,000		-340,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-343,000		-340,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-343,000		-340,000
Ohio Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-448,000		3,233,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		3,233,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		3,233,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		3,233,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		3,233,000
Ohio Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-448,000		-36,000
Commodity	'		'
Subtotal - Commodity	-689,000		-55,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-689,000		-55,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-689,000		-55,000
Income Tax (Expense) Credit	-241,000		-19,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		-36,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-689,000		-55,000
Income Tax (Expense) Credit	-241,000		-19,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		-36,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-689,000		-55,000
Income Tax (Expense) Credit	-241,000		-19,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		-36,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-448,000		-36,000
Ohio Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	0		3,269,000
Commodity	'		'
Subtotal - Commodity	0		5,029,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	0		5,029,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	0		5,029,000
Income Tax (Expense) Credit	0		1,760,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		3,269,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	0		5,029,000
Income Tax (Expense) Credit	0		1,760,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		3,269,000
Pension and OPEB	'		'
Amortization of Prior Service Cost (Credit)	0		-1,468,000
Amortization of Actuarial (Gains)/Losses	0		6,497,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	0		5,029,000
Income Tax (Expense) Credit	0		1,760,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		3,269,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	0		3,269,000
Ohio Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Vertically Integrated Utilities Revenues	0		134,000
Purchased Electricity for Resale	0		382,000
Other Operation Expense	-11,000		-18,000
Maintenance Expense	-11,000		-12,000
Property, Plant and Equipment	-18,000		-19,000
Regulatory Assets/(Liabilities), Net	-122,000	[1]	0	[1]
Subtotal - Commodity	-162,000		467,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-162,000		467,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-162,000		467,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-162,000		467,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-162,000		467,000
Ohio Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Subtotal - Commodity	-527,000		-522,000
Interest Rate and Foreign Currency	'		'
Depreciation and Amortization Expense	-3,000		2,000
Interest Expense	-524,000		-524,000
Subtotal - Interest Rate and Foreign Currency	-527,000		-522,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-527,000		-522,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	-524,000		-524,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-527,000		-522,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-527,000		-522,000
Public Service Co Of Oklahoma [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	5,758,000		6,481,000
Change in Fair Value Recognized in AOCI	0		36,000
Amounts Reclassified from AOCI	-246,000		-203,000
Net Current Period Other Comprehensive Income	-246,000		-167,000
Ending Balance in AOCI	5,512,000		6,314,000
Commodity	'		'
Vertically Integrated Utilities Revenues	296,710,000		259,903,000
Generation & Marketing Revenues	78,000		552,000
Purchased Electricity for Resale	79,691,000		64,655,000
Other Operation Expense	58,711,000		47,807,000
Maintenance Expense	24,745,000		28,572,000
Interest Rate and Foreign Currency	'		'
Depreciation and Amortization Expense	23,982,000		24,180,000
Interest Expense	13,317,000		13,340,000
Income Tax (Expense) Credit	-4,989,000		-8,634,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-246,000		-203,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	13,317,000		13,340,000
Income Tax (Expense) Credit	-4,989,000		-8,634,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-246,000		-203,000
Pension and OPEB	'		'
Income Tax (Expense) Credit	-4,989,000		-8,634,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-246,000		-203,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-246,000		-203,000
Public Service Co Of Oklahoma [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	57,000		21,000
Change in Fair Value Recognized in AOCI	0		36,000
Amounts Reclassified from AOCI	-57,000		-13,000
Net Current Period Other Comprehensive Income	-57,000		23,000
Ending Balance in AOCI	0		44,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-57,000		-13,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-57,000		-13,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-57,000		-13,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-57,000		-13,000
Public Service Co Of Oklahoma [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	5,701,000		6,460,000
Change in Fair Value Recognized in AOCI	0		0
Amounts Reclassified from AOCI	-189,000		-190,000
Net Current Period Other Comprehensive Income	-189,000		-190,000
Ending Balance in AOCI	5,512,000		6,270,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-189,000		-190,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-189,000		-190,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-189,000		-190,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-189,000		-190,000
Public Service Co Of Oklahoma [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-246,000		-203,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-246,000		-203,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-246,000		-203,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-246,000		-203,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-246,000		-203,000
Public Service Co Of Oklahoma [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Subtotal - Commodity	-380,000		-312,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-380,000		-312,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-380,000		-312,000
Income Tax (Expense) Credit	-134,000		-109,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-380,000		-312,000
Income Tax (Expense) Credit	-134,000		-109,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-380,000		-312,000
Income Tax (Expense) Credit	-134,000		-109,000
Public Service Co Of Oklahoma [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Other Operation Expense	-8,000		-9,000
Maintenance Expense	-9,000		-4,000
Property, Plant and Equipment	-13,000		-7,000
Regulatory Assets/(Liabilities), Net	-58,000	[1]	0	[1]
Subtotal - Commodity	-88,000		-20,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-88,000		-20,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-88,000		-20,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-88,000		-20,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-88,000		-20,000
Public Service Co Of Oklahoma [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Subtotal - Commodity	-292,000		-292,000
Interest Rate and Foreign Currency	'		'
Interest Expense	-292,000		-292,000
Subtotal - Interest Rate and Foreign Currency	-292,000		-292,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-292,000		-292,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	-292,000		-292,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-292,000		-292,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-292,000		-292,000
Southwestern Electric Power Co [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	-8,444,000		-17,860,000
Change in Fair Value Recognized in AOCI	0		44,000
Amounts Reclassified from AOCI	268,000		489,000
Net Current Period Other Comprehensive Income	268,000		533,000
Ending Balance in AOCI	-8,176,000		-17,327,000
Commodity	'		'
Vertically Integrated Utilities Revenues	426,627,000		381,277,000
Generation & Marketing Revenues	365,000		331,000
Purchased Electricity for Resale	61,165,000		39,760,000
Other Operation Expense	68,537,000		59,448,000
Maintenance Expense	30,411,000		27,791,000
Interest Rate and Foreign Currency	'		'
Depreciation and Amortization Expense	45,661,000		44,882,000
Interest Expense	31,876,000		33,990,000
Income Tax (Expense) Credit	-12,165,000		-6,796,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	268,000		489,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	31,876,000		33,990,000
Income Tax (Expense) Credit	-12,165,000		-6,796,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	268,000		489,000
Pension and OPEB	'		'
Income Tax (Expense) Credit	-12,165,000		-6,796,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	268,000		489,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	268,000		489,000
Southwestern Electric Power Co [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	4,794,000		-2,311,000
Change in Fair Value Recognized in AOCI	0		0
Amounts Reclassified from AOCI	-234,000		-63,000
Net Current Period Other Comprehensive Income	-234,000		-63,000
Ending Balance in AOCI	4,560,000		-2,374,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-234,000		-63,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-234,000		-63,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-234,000		-63,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-234,000		-63,000
Southwestern Electric Power Co [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	66,000		22,000
Change in Fair Value Recognized in AOCI	0		44,000
Amounts Reclassified from AOCI	-66,000		-15,000
Net Current Period Other Comprehensive Income	-66,000		29,000
Ending Balance in AOCI	0		51,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-66,000		-15,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-66,000		-15,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-66,000		-15,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-66,000		-15,000
Southwestern Electric Power Co [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Beginning Balance in AOCI	-13,304,000		-15,571,000
Change in Fair Value Recognized in AOCI	0		0
Amounts Reclassified from AOCI	568,000		567,000
Net Current Period Other Comprehensive Income	568,000		567,000
Ending Balance in AOCI	-12,736,000		-15,004,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	568,000		567,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	568,000		567,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	568,000		567,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	568,000		567,000
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	268,000		489,000
Interest Rate and Foreign Currency	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	268,000		489,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	268,000		489,000
Pension and OPEB	'		'
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	268,000		489,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	268,000		489,000
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Cash Flow Hedges [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	502,000		552,000
Commodity	'		'
Subtotal - Commodity	771,000		849,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	771,000		849,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	771,000		849,000
Income Tax (Expense) Credit	269,000		297,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	502,000		552,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	771,000		849,000
Income Tax (Expense) Credit	269,000		297,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	502,000		552,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	771,000		849,000
Income Tax (Expense) Credit	269,000		297,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	502,000		552,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	502,000		552,000
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Pension and OPEB [Member]	'		'
Changes in Accumulated Other Comprehensive Income (Loss) by Component	'		'
Amounts Reclassified from AOCI	-234,000		-63,000
Commodity	'		'
Subtotal - Commodity	-360,000		-97,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-360,000		-97,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-360,000		-97,000
Income Tax (Expense) Credit	-126,000		-34,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-234,000		-63,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-360,000		-97,000
Income Tax (Expense) Credit	-126,000		-34,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-234,000		-63,000
Pension and OPEB	'		'
Amortization of Prior Service Cost (Credit)	-478,000		-445,000
Amortization of Actuarial (Gains)/Losses	118,000		348,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-360,000		-97,000
Income Tax (Expense) Credit	-126,000		-34,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-234,000		-63,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit	-234,000		-63,000
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Commodity [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Other Operation Expense	-13,000		-10,000
Maintenance Expense	-10,000		-6,000
Property, Plant and Equipment	-11,000		-7,000
Regulatory Assets/(Liabilities), Net	-67,000	[1]	0	[1]
Subtotal - Commodity	-101,000		-23,000
Interest Rate and Foreign Currency	'		'
Subtotal - Interest Rate and Foreign Currency	-101,000		-23,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	-101,000		-23,000
Gains and Losses on Securities Available for Sale	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-101,000		-23,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	-101,000		-23,000
Southwestern Electric Power Co [Member] \| Reclassifications from Accumulated Other Comprehensive Income [Member] \| Interest Rate and Foreign Currency [Member] \| Cash Flow Hedges [Member]	'		'
Commodity	'		'
Subtotal - Commodity	872,000		872,000
Interest Rate and Foreign Currency	'		'
Interest Expense	872,000		872,000
Subtotal - Interest Rate and Foreign Currency	872,000		872,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	872,000		872,000
Gains and Losses on Securities Available for Sale	'		'
Interest Expense	872,000		872,000
Reclassifications from AOCI, before Income Tax (Expense) Credit	872,000		872,000
Pension and OPEB	'		'
Reclassifications from AOCI, before Income Tax (Expense) Credit	$872,000		$872,000

[1]	Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

Rate_Matters_Details

Rate Matters (Details) (USD $)

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Apr. 25, 2014

Mar. 31, 2014

Apr. 25, 2014

Mar. 31, 2014

Apr. 25, 2014

Mar. 31, 2014

Apr. 25, 2014

Mar. 31, 2014

Apr. 25, 2014

Mar. 31, 2014

Apr. 25, 2014

Mar. 31, 2014

Tanners Creek Plant, Units 1-4 [Member]

Big Sandy Plant, Unit 2 [Member]

Regulatory Assets Not Yet Being Recovered [Member]

Ohio Economic Development Rider [Member]

Expanded Net Energy Charge - Coal Inventory [Member]

IGCC Pre-Construction Costs [Member]

Indiana Under-Recovered Capacity Costs

Mountaineer Carbon Capture and Storage Product Validation Facility [Member]

Other Regulatory Assets Not Yet Being Recovered [Member]

Ormet Special Rate Recovery Mechanism [Member]

Storm Costs [Member]

Appalachian Power Co [Member]

Southwestern Electric Power Co [Member]

Ohio Power Co [Member]

Public Service Co Of Oklahoma [Member]

Indiana Michigan Power Co [Member]

APCo's Filing for IGCC Plant [Member]

Cook Plant Life Cycle Management Project [Member]

Indiana 2011 Base Rate Case [Member]

Louisiana 2012 Formula Rate Filing [Member]

Louisiana 2014 Formula Rate Filing [Member]

Ohio Electric Security Plan Filing [Member]

Ohio Fuel Adjustment Clause Audit - 2009 [Member]

Ohio IGCC Plant [Member]

Plant Transfer [Member]

Oklahoma 2014 Base Rate Case [Member]

Ormet

Storm Damage Recovery Rider [Member]

Texas 2012 Base Rate Case [Member]

Texas Transmission Cost Recovery Factor Filing - 2013 [Member]

Virginia 2014 Biennial Base Rate Case [Member]

Virginia Transmission Rate Adjustment Clause - 2013 [Member]

Regulatory Assets Not Yet Being Recovered [Member]

Expanded Net Energy Charge - Coal Inventory [Member]

IGCC Pre-Construction Costs [Member]

Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member]

Mountaineer Carbon Capture and Storage Product Validation Facility [Member]

Other Regulatory Assets Not Yet Being Recovered [Member]

Storm Costs [Member]

Transmission Agreement Phase-In [Member]

Virginia Demand Response Program Costs [Member]

Virginia Environmental Rate Adjustment Clause [Member]

Regulatory Assets Not Yet Being Recovered [Member]

Mountaineer Carbon Capture and Storage Commercial Scale Facility [Member]

Other Regulatory Assets Not Yet Being Recovered [Member]

Rate Case Expenses [Member]

Regulatory Assets Not Yet Being Recovered [Member]

Ohio Economic Development Rider [Member]

Ormet Special Rate Recovery Mechanism [Member]

Storm Costs [Member]

Regulatory Assets Not Yet Being Recovered [Member]

Other Regulatory Assets Not Yet Being Recovered [Member]

Storm Costs [Member]

Tanners Creek Plant, Units 1-4 [Member]

Regulatory Assets Not Yet Being Recovered [Member]

Cook Plant Turbine [Member]

Indiana Deferred Cook Plant Life Cycle Management Project Costs [Member]

Indiana Under-Recovered Capacity Costs

Other Regulatory Assets Not Yet Being Recovered [Member]

Storm Costs [Member]

Stranded Costs on Abandoned Plants [Member]

Applicable to West Virginia Jurisdiction [Member]

Applicable to FERC Jurisdiction [Member]

Applicable to Virginia Jurisdiction [Member]

Indiana Michigan Power Co [Member]

Indiana Filing [Member]

Indiana Michigan Power Co [Member]

Southwestern Electric Power Co [Member]

Subsequent Event [Member]

Southwestern Electric Power Co [Member]

Deferred Capacity Costs [Member]

Deferred Fuel Costs [Member]

Ohio Power Co [Member]

Subsequent Event [Member]

Appalachian Power Co [Member]

Terms Of Kentucky Power Co Settlement Agreement [Member]

Subsequent Event [Member]

Public Service Co Of Oklahoma [Member]

Subsequent Event [Member]

Ohio Power Co [Member]

Subsequent Event [Member]

Ohio Power Co [Member]

Welsh Plant, Unit 2 [Member]

Southwestern Electric Power Co [Member]

Appalachian Power Co [Member]

Regulatory Assets Currently Earning a Return [Member]

Regulatory Assets Currently Not Earning a Return [Member]

Regulatory Assets Currently Earning a Return [Member]

Regulatory Assets Currently Not Earning a Return [Member]

Regulatory Assets Currently Earning a Return [Member]

Regulatory Assets Currently Not Earning a Return [Member]

Regulatory Assets Not Yet Being Recovered [Member]

Appalachian Power Co [Member]

Indiana Michigan Power Co [Member]

Subsequent Event [Member]

Deferred Capacity Costs [Member]

Deferred Fuel Costs [Member]

Subsequent Event [Member]

Big Sandy Plant, Unit 1 Natural Gas Conversion [Member]

Minimum [Member]

Maximum [Member]

Subsequent Event [Member]

Welsh Plant, Unit 2 [Member]

Regulatory Assets Currently Not Earning a Return [Member]

Regulatory Assets Currently Earning a Return [Member]

Regulatory Assets Currently Not Earning a Return [Member]

Minimum [Member]

Maximum [Member]

Regulatory Assets Not Being Recovered [Abstract]

Regulatory Assets, Noncurrent

$4,384,000,000

$4,376,000,000

$250,000,000

$330,000,000

$14,000,000

$19,000,000

$21,000,000

$28,000,000

$22,000,000

$13,000,000

$4,000,000

$34,000,000

$37,000,000

$10,000,000

$36,000,000

$21,000,000

$22,000,000

$104,000,000

$161,000,000

$1,006,426,000

$1,003,890,000

$130,904,000

$111,218,000

$18,818,000

$20,528,000

$1,287,000

$13,264,000

$513,000

$168,000

$65,206,000

$3,450,000

$3,313,000

$5,897,000

$5,012,000

$1,941,000

$2,440,000

$367,406,000

$369,905,000

$11,098,000

$11,028,000

$1,143,000

$2,025,000

$1,951,000

$7,930,000

$7,934,000

$1,398,055,000

$1,378,697,000

$12,118,000

$107,074,000

$13,854,000

$10,483,000

$35,631,000

$1,635,000

$57,589,000

$164,929,000

$156,690,000

$20,172,000

$19,588,000

$1,079,000

$845,000

$19,093,000

$18,743,000

$505,750,000

$524,114,000

$37,729,000

$35,386,000

$4,238,000

$3,452,000

$4,093,000

$28,149,000

$21,945,000

$694,000

$164,000

$751,000

$1,836,000

$3,897,000

$3,896,000

$348,000,000

$426,000,000

$348,000,000

$426,000,000

Rate Matters (Textuals) [Abstract]

Regulatory Assets, Noncurrent

4,384,000,000

4,376,000,000

250,000,000

330,000,000

14,000,000

19,000,000

21,000,000

28,000,000

22,000,000

13,000,000

4,000,000

34,000,000

37,000,000

10,000,000

36,000,000

21,000,000

22,000,000

104,000,000

161,000,000

1,006,426,000

1,003,890,000

130,904,000

111,218,000

18,818,000

20,528,000

1,287,000

13,264,000

513,000

168,000

65,206,000

3,450,000

3,313,000

5,897,000

5,012,000

1,941,000

2,440,000

367,406,000

369,905,000

11,098,000

11,028,000

1,143,000

2,025,000

1,951,000

7,930,000

7,934,000

1,398,055,000

1,378,697,000

12,118,000

107,074,000

13,854,000

10,483,000

35,631,000

1,635,000

57,589,000

164,929,000

156,690,000

20,172,000

19,588,000

1,079,000

845,000

19,093,000

18,743,000

505,750,000

524,114,000

37,729,000

35,386,000

4,238,000

3,452,000

4,093,000

28,149,000

21,945,000

694,000

164,000

751,000

1,836,000

3,897,000

3,896,000

348,000,000

426,000,000

348,000,000

426,000,000

Potential Refund of Carrying Costs Due to an Accumulated Deferred Income Tax Credit

30,000,000

Potential Refund of Unrecognized Equity Carrying Costs Due to an Accumulated Deferred Income Tax Credit

16,000,000

Future Commitment to Support the Development of a Large Solar Farm

20,000,000

PUCO Ordered Fixed Price per MW Day for Customers Who Switch During ESP Period

188.88

Reliability Pricing Model Rate per MW Day in Effect Through May 2014

Reliability Pricing Model Rate per MW Day in Effect from June 2014 Through May 2015

148

Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh)

Retail Stability Rider through May 2014 ($ Per MWh)

3.5

Amount of Retail Stability Rider Applied to the Deferred Capacity Costs for the Period June 2014 through May 2015 ($ per MWh)

Percentage of Standard Service Offer Load Which Registrant Will Conduct an Energy Only Auction for Delivery through May 2015

10.00%

Additional Percentage of Standard Service Offer Load Which Registrant Will Conduct an Energy Only Auction for Delivery Beginning November 2014 through May 2015

50.00%

Remaining Percentage of Standard Service Offer Load Which Registrant Will Conduct an Energy Only Auction for Delivery from January 2015 through May 2015

40.00%

Requested Return on Equity on Capital Costs for Certain Riders

10.65%

Estimated Average Decrease in Customer Rates Over Three Years

9.00%

Intended Retail Stability Rider Rate To Be Continued Until Capacity Deferral Balance Is Collected

Recommended Amount of Storm Cost Recovery as Approved in Stipulation Agreement

55,000,000

Reduction in the 2012 Storm Expenses as Approved in the Stipulation Agreement

6,000,000

2008 Coal Contract Settlement Proceeds to be Applied to Deferred Fuel Adjustment Clause as Orginially Ordered by the PUCO

65,000,000

Net Favorable Fuel Adjustment Recorded in 2012 Based on Fuel Adjustment Clause Audit Rehearing

30,000,000

Remaining Retail Gain Not Already Flowed Through Fuel Adjustment Clause

35,000,000

Maximum Amount of Ormet's October and November 2012 Unpaid Balance Allowed to be Recovered in the Economic Development Rider

20,000,000

Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Proposed in the Stipulation Agreement

49,000,000

Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Approved in the Economic Development Rider Filing

39,000,000

Remaining Ormet Deferral Allowed to be Requested Upon PUCO Adoption of Ormet Stipulation Agreement

10,000,000

Amount of Remaining Foregone Revenues Objected to by an Intervenor

5,000,000

Deferred Fuel Adjustment Clause Related to Ormet Interim Arrangement as of September 2009

64,000,000

Unrecognized Equity Carrying Costs Related to Ormet Interim Arrangement as of September 2009

2,000,000

Collection of Authorized Pre-Construction Costs

24,000,000

Property, Plant and Equipment, Net

334,000,000

247,000,000

334,000,000

86,000,000

Reversal of Previously Recorded Regulatory Disallowances

114,000,000

Resulting Approved Base Rate Increase

52,000,000

Requested Transmission Cost Recovery Factor Revenue

10,000,000

Louisiana Jurisdictional Share of the Turk Plant

29.00%

Net Increase in Louisiana Total Rates per the Settlement Agreement

2,000,000

Base Rate Increase per the Settlement Agreement

85,000,000

Fuel Rate Decrease per the Settlement Agreement

83,000,000

Return on Common Equity per the Settlement Agreement

10.00%

Requested Annual Increase

5,000,000

Additional Requested Annual Increase

15,000,000

Requested Total Annual Increase

20,000,000

Proposed Base Rate Surcharge

113,000,000

Amount of Deferred Preconstruction IGCC Costs for Future Recovery

9,000,000

2,000,000

10,000,000

Requested Increase In Virginia Transmission Rate Adjustment Clause Revenues

50,000,000

Annual Revenue Increase as Approved in Stipulation Agreement

49,000,000

Approved Return On Equity

10.20%

10.90%

Requested Annual Amortization of Certain Deferred Costs

7,000,000

Requested Base Rate Increase

38,000,000

Requested Return on Equity

10.50%

Proposed Depreciation Increase Included in Requested Rate Increase

29,000,000

Year One Revenues Related to Proposed Recovery of Advanced Metering Costs

7,000,000

Year Three Revenues Related to Proposed Recovery of Advanced Metering Costs

28,000,000

Intervenor Recommended Reduction to the Requested Increase in Annual Base Rate

16,000,000

Intervenor Recommended Reduction in Annual Base Rates

22,000,000

Intervenor Recommended Return on Common Equity Range

9.18%

9.50%

9.18%

9.50%

Approved Base Rate Increase

85,000,000

Revised Approved Base Rate Increase

92,000,000

Projected Capital Costs

1,200,000,000

60,000,000

Construction Work in Progress

2,836,000,000

2,471,000,000

217,713,000

184,701,000

309,200,000

281,849,000

188,636,000

185,428,000

172,949,000

175,890,000

476,734,000

427,164,000

405,000,000

Amount Excluded from Indiana Utility Regulatory Commission LCM Project Approval

23,000,000

Annual Amount of Asset Transfer Rider

44,000,000

Annual Level of Off System Sales Margins in Base Rates Above Which is Proposed to be Retained by Kentucky Power Company

15,300,000

Asset Impairments and Other Related Charges

$33,000,000

Commitments_Guarantees_and_Con2

Commitments, Guarantees and Contingencies (Details) (USD $)	3 Months Ended
Commitments, Guarantees and Contingencies (Details) (USD $)	Mar. 31, 2014
Letters of Credit [Member]	'
Maximum Future Payments for Letters of Credit [Abstract]	'
Maximum Future Payments for Letters of Credit	$130,000,000
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]	'
Variable Rate PCBs Supported	352,000,000
Bilateral Letters of Credit	356,000,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Revolving Credit Facilities	3,500,000,000
Letters of Credit Limit	1,200,000,000
Maximum Future Payments for Letters of Credit	130,000,000
Uncommitted Facility	85,000,000
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	75,000,000
Variable Rate PCBs Supported	352,000,000
Bilateral Letters of Credit	356,000,000
Master Lease Agreements [Member]	'
Maximum Potential Loss on Master Lease Agreements [Abstract]	'
Max Potential Loss on Master Lease Agreements	21,000,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Max Potential Loss on Master Lease Agreements	21,000,000
Guarantees of Third Party Obligations [Member]	'
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Guarantees of Mine Reclamation, Amount	115,000,000
Estimated Final Cost Mine Reclamation	58,000,000
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs	62,000,000
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent	16,000,000
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	46,000,000
Indiana Michigan Power Co [Member] \| Letters of Credit [Member]	'
Maximum Future Payments for Letters of Credit [Abstract]	'
Maximum Future Payments for Letters of Credit	150,000
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]	'
Variable Rate PCBs Supported	77,000,000
Bilateral Letters of Credit	77,886,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Maximum Future Payments for Letters of Credit	150,000
Variable Rate PCBs Supported	77,000,000
Bilateral Letters of Credit	77,886,000
Indiana Michigan Power Co [Member] \| Master Lease Agreements [Member]	'
Maximum Potential Loss on Master Lease Agreements [Abstract]	'
Max Potential Loss on Master Lease Agreements	2,580,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Max Potential Loss on Master Lease Agreements	2,580,000
Future Minimum Lease Obligation for Remaining Railcars	13,000,000
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term	83.00%
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term	77.00%
Maximum Potential Loss on Guarantee of Return-and-Sale Option	9,000,000
Southwestern Electric Power Co [Member] \| Master Lease Agreements [Member]	'
Maximum Potential Loss on Master Lease Agreements [Abstract]	'
Max Potential Loss on Master Lease Agreements	2,486,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Max Potential Loss on Master Lease Agreements	2,486,000
Future Minimum Lease Obligation for Remaining Railcars	15,000,000
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor Current Term	83.00%
Guaranteed Sales Proceeds Percentage of Fair Value to Lessor End of Max Lease Term	77.00%
Maximum Potential Loss on Guarantee of Return-and-Sale Option	10,000,000
Southwestern Electric Power Co [Member] \| Guarantees of Third Party Obligations [Member]	'
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Guarantees of Mine Reclamation, Amount	115,000,000
Estimated Final Cost Mine Reclamation	58,000,000
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs	62,000,000
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent	16,000,000
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	46,000,000
Ohio Power Co [Member] \| Letters of Credit [Member]	'
Maximum Future Payments for Letters of Credit [Abstract]	'
Maximum Future Payments for Letters of Credit	3,081,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Maximum Future Payments for Letters of Credit	3,081,000
Ohio Power Co [Member] \| Master Lease Agreements [Member]	'
Maximum Potential Loss on Master Lease Agreements [Abstract]	'
Max Potential Loss on Master Lease Agreements	4,384,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Max Potential Loss on Master Lease Agreements	4,384,000
Appalachian Power Co [Member] \| Letters of Credit [Member]	'
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]	'
Variable Rate PCBs Supported	229,650,000
Bilateral Letters of Credit	232,293,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Variable Rate PCBs Supported	229,650,000
Bilateral Letters of Credit	232,293,000
Appalachian Power Co [Member] \| Master Lease Agreements [Member]	'
Maximum Potential Loss on Master Lease Agreements [Abstract]	'
Max Potential Loss on Master Lease Agreements	3,772,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Max Potential Loss on Master Lease Agreements	3,772,000
Public Service Co Of Oklahoma [Member] \| Master Lease Agreements [Member]	'
Maximum Potential Loss on Master Lease Agreements [Abstract]	'
Max Potential Loss on Master Lease Agreements	1,347,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Max Potential Loss on Master Lease Agreements	1,347,000
Superfund and State Remediation [Member]	'
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Expense Recorded Due to Remediation Work Remaining Provision	8,000,000
Superfund and State Remediation [Member] \| Indiana Michigan Power Co [Member]	'
Commitments, Guarantees and Contingencies (Textuals) [Abstract]	'
Expense Recorded Due to Remediation Work Remaining Provision	$8,000,000

Acquisitions_Dispositions_and_

Acquisitions Dispositions and Discontinued Operations (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Acquisitions Dispositions and Discontinued Operations (Textuals) [Abstract]	'	'	'
Acquisitions of Assets	$43	$2	'
Goodwill	$91	'	$91

Benefit_Plans_Details

Benefit Plans (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Pension Plans [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	$18,000	$17,000
Interest Cost	55,000	50,000
Expected Return on Plan Assets	-66,000	-69,000
Amortization of Prior Service Cost (Credit)	1,000	1,000
Amortization of Net Actuarial Loss	31,000	46,000
Net Periodic Benefit Cost (Credit)	39,000	45,000
Pension Plans [Member] \| Appalachian Power Co [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	1,759	1,543
Interest Cost	7,406	6,916
Expected Return on Plan Assets	-8,482	-9,260
Amortization of Prior Service Cost (Credit)	50	49
Amortization of Net Actuarial Loss	4,148	6,256
Net Periodic Benefit Cost (Credit)	4,881	5,504
Pension Plans [Member] \| Indiana Michigan Power Co [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	2,517	2,184
Interest Cost	6,573	6,025
Expected Return on Plan Assets	-7,748	-8,207
Amortization of Prior Service Cost (Credit)	49	49
Amortization of Net Actuarial Loss	3,646	5,422
Net Periodic Benefit Cost (Credit)	5,037	5,473
Pension Plans [Member] \| Ohio Power Co [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	1,285	2,372
Interest Cost	5,526	10,292
Expected Return on Plan Assets	-6,607	-15,141
Amortization of Prior Service Cost (Credit)	39	71
Amortization of Net Actuarial Loss	3,106	9,309
Net Periodic Benefit Cost (Credit)	3,349	6,903
Pension Plans [Member] \| Public Service Co Of Oklahoma [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	1,302	1,391
Interest Cost	3,014	2,748
Expected Return on Plan Assets	-3,651	-3,918
Amortization of Prior Service Cost (Credit)	74	74
Amortization of Net Actuarial Loss	1,688	2,461
Net Periodic Benefit Cost (Credit)	2,427	2,756
Pension Plans [Member] \| Southwestern Electric Power Co [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	1,655	1,753
Interest Cost	3,163	2,864
Expected Return on Plan Assets	-3,857	-4,127
Amortization of Prior Service Cost (Credit)	87	87
Amortization of Net Actuarial Loss	1,761	2,553
Net Periodic Benefit Cost (Credit)	2,809	3,130
Other Postretirement Benefit Plans [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	4,000	6,000
Interest Cost	17,000	18,000
Expected Return on Plan Assets	-28,000	-27,000
Amortization of Prior Service Cost (Credit)	-17,000	-17,000
Amortization of Net Actuarial Loss	5,000	16,000
Net Periodic Benefit Cost (Credit)	-19,000	-4,000
Other Postretirement Benefit Plans [Member] \| Appalachian Power Co [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	362	641
Interest Cost	3,197	3,363
Expected Return on Plan Assets	-4,633	-4,536
Amortization of Prior Service Cost (Credit)	-2,513	-2,512
Amortization of Net Actuarial Loss	1,146	3,062
Net Periodic Benefit Cost (Credit)	-2,441	18
Other Postretirement Benefit Plans [Member] \| Indiana Michigan Power Co [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	487	805
Interest Cost	1,909	2,055
Expected Return on Plan Assets	-3,364	-3,296
Amortization of Prior Service Cost (Credit)	-2,355	-2,355
Amortization of Net Actuarial Loss	592	1,882
Net Periodic Benefit Cost (Credit)	-2,731	-909
Other Postretirement Benefit Plans [Member] \| Ohio Power Co [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	256	1,300
Interest Cost	1,901	4,447
Expected Return on Plan Assets	-3,380	-6,238
Amortization of Prior Service Cost (Credit)	-1,731	-3,231
Amortization of Net Actuarial Loss	595	4,041
Net Periodic Benefit Cost (Credit)	-2,359	319
Other Postretirement Benefit Plans [Member] \| Public Service Co Of Oklahoma [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	210	343
Interest Cost	893	948
Expected Return on Plan Assets	-1,575	-1,522
Amortization of Prior Service Cost (Credit)	-1,072	-1,072
Amortization of Net Actuarial Loss	277	869
Net Periodic Benefit Cost (Credit)	-1,267	-434
Other Postretirement Benefit Plans [Member] \| Southwestern Electric Power Co [Member]	'	'
Components of Net Periodic Benefit Cost	'	'
Service Cost	253	423
Interest Cost	998	1,075
Expected Return on Plan Assets	-1,754	-1,720
Amortization of Prior Service Cost (Credit)	-1,289	-1,288
Amortization of Net Actuarial Loss	309	982
Net Periodic Benefit Cost (Credit)	($1,483)	($528)

Business_Segments_Details

Business Segments (Details) (USD $)	3 Months Ended
Business Segments (Details) (USD $)	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Reportable Segment Information	'		'		'
Revenues	$4,648,000,000		$3,826,000,000		'
Net Income (Loss)	561,000,000		364,000,000		'
Balance Sheet Information	'		'		'
Total Property, Plant and Equipment	61,094,000,000		'		60,285,000,000
Accumulated Depreciation and Amortization	19,564,000,000		'		19,288,000,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	41,530,000,000		'		40,997,000,000
Total Assets	57,038,000,000		'		56,414,000,000
Reconciling Adjustments [Member]	'		'		'
Reportable Segment Information	'		'		'
Net Income (Loss)	0		0		'
Balance Sheet Information	'		'		'
Total Property, Plant and Equipment	-272,000,000	[1]	'		-269,000,000	[1]
Accumulated Depreciation and Amortization	-88,000,000	[1]	'		-85,000,000	[1]
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	-184,000,000	[1]	'		-184,000,000	[1]
Total Assets	-19,606,000,000	[1],[2]	'		-19,531,000,000	[1],[2]
Vertically Integrated Utilities [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	2,549,000,000	[3]	2,356,000,000		'
Revenues	2,586,000,000		2,515,000,000		'
Net Income (Loss)	279,000,000		181,000,000		'
Balance Sheet Information	'		'		'
Total Property, Plant and Equipment	37,923,000,000		'		37,545,000,000
Accumulated Depreciation and Amortization	12,424,000,000		'		12,250,000,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	25,499,000,000		'		25,295,000,000
Total Assets	32,997,000,000		'		32,791,000,000
Vertically Integrated Utilities [Member] \| Significant Reconciling Items [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	37,000,000	[3]	159,000,000		'
Transmission And Distribution Utilities [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	1,161,000,000		1,090,000,000		'
Revenues	1,215,000,000		1,134,000,000		'
Net Income (Loss)	97,000,000		87,000,000		'
Balance Sheet Information	'		'		'
Total Property, Plant and Equipment	12,339,000,000		'		12,143,000,000
Accumulated Depreciation and Amortization	3,382,000,000		'		3,342,000,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	8,957,000,000		'		8,801,000,000
Total Assets	13,899,000,000		'		14,165,000,000
Transmission And Distribution Utilities [Member] \| Significant Reconciling Items [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	54,000,000		44,000,000		'
AEP Transmission Holdco [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	12,000,000		3,000,000		'
Revenues	28,000,000		8,000,000		'
Net Income (Loss)	24,000,000		12,000,000		'
Balance Sheet Information	'		'		'
Total Property, Plant and Equipment	1,842,000,000		'		1,636,000,000
Accumulated Depreciation and Amortization	13,000,000		'		10,000,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	1,829,000,000		'		1,626,000,000
Total Assets	2,460,000,000		'		2,245,000,000
AEP Transmission Holdco [Member] \| Significant Reconciling Items [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	16,000,000		5,000,000		'
AEP River Operations [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	146,000,000		128,000,000		'
Revenues	165,000,000		133,000,000		'
Net Income (Loss)	3,000,000		-2,000,000		'
Balance Sheet Information	'		'		'
Total Property, Plant and Equipment	639,000,000		'		638,000,000
Accumulated Depreciation and Amortization	197,000,000		'		189,000,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	442,000,000		'		449,000,000
Total Assets	659,000,000		'		673,000,000
AEP River Operations [Member] \| Significant Reconciling Items [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	19,000,000		5,000,000		'
Generation and Marketing [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	821,000,000	[3]	258,000,000		'
Revenues	1,251,000,000		920,000,000		'
Net Income (Loss)	163,000,000		85,000,000		'
Balance Sheet Information	'		'		'
Total Property, Plant and Equipment	8,302,000,000		'		8,277,000,000
Accumulated Depreciation and Amortization	3,460,000,000		'		3,409,000,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	4,842,000,000		'		4,868,000,000
Total Assets	6,354,000,000		'		6,426,000,000
Generation and Marketing [Member] \| Significant Reconciling Items [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	430,000,000	[3]	662,000,000		'
All Other [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	10,000,000	[4]	5,000,000	[4]	'
Revenues	26,000,000	[4]	18,000,000	[4]	'
Net Income (Loss)	-5,000,000	[4]	1,000,000	[4]	'
Balance Sheet Information	'		'		'
Total Property, Plant and Equipment	321,000,000	[4]	'		315,000,000	[4]
Accumulated Depreciation and Amortization	176,000,000	[4]	'		173,000,000	[4]
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	145,000,000	[4]	'		142,000,000	[4]
Total Assets	20,275,000,000	[4]	'		19,645,000,000	[4]
All Other [Member] \| Significant Reconciling Items [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	16,000,000	[4]	13,000,000	[4]	'
Consolidation Eliminations [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	-51,000,000	[5]	-14,000,000	[5]	'
Revenues	-623,000,000		-902,000,000		'
Consolidation Eliminations [Member] \| Reconciling Adjustments [Member]	'		'		'
Reportable Segment Information	'		'		'
Sales Revenue, Net	($572,000,000)		($888,000,000)		'

[1]	Includes eliminations due to an intercompany capital lease.
[2]	Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEPbs investments in subsidiary companies.
[3]	Includes the impact of the corporate separation of OPCobs 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.
[4]	Corporate and Other primarily includes management and professional services to AEP provided at cost to AEP subsidiaries and the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parentbs guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
[5]	Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation.

Derivatives_and_Hedging_Detail

Derivatives and Hedging (Details) (USD $)	3 Months Ended				12 Months Ended
Derivatives and Hedging (Details) (USD $)	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Cash Collateral Netting	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	$19,000,000		'		$4,000,000
Cash Collateral Paid Netted Against Risk Management Liabilities	17,000,000		'		13,000,000
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	125,000,000		'		160,000,000
Long-term Risk Management Assets	266,000,000		'		297,000,000
Total Assets	391,000,000		'		457,000,000
Current Risk Management Liabilities	60,000,000		'		90,000,000
Long-term Risk Management Liabilities	137,000,000		'		177,000,000
Total Liabilities	197,000,000		'		267,000,000
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	139,000,000		18,000,000		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	13,000,000	[1]	'		7,000,000	[1]
Hedging Liabilities	7,000,000	[1]	'		8,000,000	[1]
AOCI Gain (Loss) Net of Tax	-18,000,000		'		-23,000,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	-1,000,000		'		-4,000,000
Maximum Term for Exposure to Variability of Future Cash Flows	'41 months		'		'
Collateral Triggering Events [Abstract]	'		'		'
Liabilities for Derivative Contracts with Credit Downgrade Triggers	2,000,000		'		3,000,000
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post	144,000,000		'		33,000,000
Amount Attributable to RTO and ISO Activities	38,000,000		'		28,000,000
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements	225,000,000		'		293,000,000
Amount of Cash Collateral Posted	0		'		1,000,000
Additional Settlement Liability if Cross Default Provision is Triggered	177,000,000		'		235,000,000
Derivatives and Hedging (Textuals) [Abstract]	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	19,000,000		'		4,000,000
Cash Collateral Paid Netted Against Risk Management Liabilities	17,000,000		'		13,000,000
Maximum Term for Exposure to Variability of Future Cash Flows	'41 months		'		'
Gain (Loss) on Fair Value Hedging Instrument	2,000,000		-1,000,000		'
Gain (Loss) on Fair Value Portion of Long Term Debt	-2,000,000		1,000,000		'
Appalachian Power Co [Member]	'		'		'
Cash Collateral Netting	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	32,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	1,362,000		'		2,993,000
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	15,972,000		'		21,171,000
Long-term Risk Management Assets	14,013,000		'		16,948,000
Total Assets	29,985,000		'		38,119,000
Current Risk Management Liabilities	4,636,000		'		8,892,000
Long-term Risk Management Liabilities	7,929,000		'		10,241,000
Total Liabilities	12,565,000		'		19,133,000
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	37,183,000		213,000		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Maximum Term for Exposure to Variability of Future Cash Flows	'2 months		'		'
Collateral Triggering Events [Abstract]	'		'		'
Liabilities for Derivative Contracts with Credit Downgrade Triggers	285,000		'		575,000
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post	5,254,000		'		2,747,000
Amount Attributable to RTO and ISO Activities	4,774,000		'		2,539,000
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements	16,375,000		'		19,648,000
Amount of Cash Collateral Posted	0		'		0
Additional Settlement Liability if Cross Default Provision is Triggered	12,865,000		'		18,568,000
Derivatives and Hedging (Textuals) [Abstract]	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	32,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	1,362,000		'		2,993,000
Maximum Term for Exposure to Variability of Future Cash Flows	'2 months		'		'
Indiana Michigan Power Co [Member]	'		'		'
Cash Collateral Netting	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	21,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	924,000		'		2,030,000
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	12,558,000		'		15,388,000
Long-term Risk Management Assets	9,505,000		'		11,495,000
Total Assets	22,063,000		'		26,883,000
Current Risk Management Liabilities	4,134,000		'		7,029,000
Long-term Risk Management Liabilities	5,378,000		'		6,946,000
Total Liabilities	9,512,000		'		13,975,000
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	24,252,000		251,000		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Maximum Term for Exposure to Variability of Future Cash Flows	'2 months		'		'
Collateral Triggering Events [Abstract]	'		'		'
Liabilities for Derivative Contracts with Credit Downgrade Triggers	190,000		'		390,000
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post	3,560,000		'		1,863,000
Amount Attributable to RTO and ISO Activities	3,238,000		'		1,722,000
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements	11,107,000		'		13,326,000
Amount of Cash Collateral Posted	0		'		0
Additional Settlement Liability if Cross Default Provision is Triggered	8,726,000		'		12,594,000
Derivatives and Hedging (Textuals) [Abstract]	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	21,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	924,000		'		2,030,000
Maximum Term for Exposure to Variability of Future Cash Flows	'2 months		'		'
Ohio Power Co [Member]	'		'		'
Cash Collateral Netting	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	3,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	0		'		0
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	3,980,000		'		3,082,000
Total Assets	'		'		3,082,000
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	35,099,000		509,000		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Maximum Term for Exposure to Variability of Future Cash Flows	'0 months		'		'
Collateral Triggering Events [Abstract]	'		'		'
Liabilities for Derivative Contracts with Credit Downgrade Triggers	78,000		'		349,000
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post	0		'		0
Amount Attributable to RTO and ISO Activities	0		'		0
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements	0		'		0
Amount of Cash Collateral Posted	0		'		0
Additional Settlement Liability if Cross Default Provision is Triggered	0		'		0
Derivatives and Hedging (Textuals) [Abstract]	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	3,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	0		'		0
Maximum Term for Exposure to Variability of Future Cash Flows	'0 months		'		'
Public Service Co Of Oklahoma [Member]	'		'		'
Cash Collateral Netting	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	1,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	0		'		1,000
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	1,349,000		'		1,167,000
Total Assets	'		'		1,167,000
Current Risk Management Liabilities	83,000		'		85,000
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	767,000		2,058,000		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Maximum Term for Exposure to Variability of Future Cash Flows	'0 months		'		'
Collateral Triggering Events [Abstract]	'		'		'
Liabilities for Derivative Contracts with Credit Downgrade Triggers	132,000		'		0
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post	4,156,000		'		2,930,000
Amount Attributable to RTO and ISO Activities	0		'		410,000
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements	0		'		3,000
Amount of Cash Collateral Posted	0		'		0
Additional Settlement Liability if Cross Default Provision is Triggered	0		'		3,000
Derivatives and Hedging (Textuals) [Abstract]	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	1,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	0		'		1,000
Maximum Term for Exposure to Variability of Future Cash Flows	'0 months		'		'
Southwestern Electric Power Co [Member]	'		'		'
Cash Collateral Netting	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	2,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	0		'		3,000
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	1,907,000		'		1,179,000
Total Assets	'		'		1,179,000
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	1,356,000		395,000		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Maximum Term for Exposure to Variability of Future Cash Flows	'0 months		'		'
Collateral Triggering Events [Abstract]	'		'		'
Liabilities for Derivative Contracts with Credit Downgrade Triggers	167,000		'		0
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post	145,000		'		713,000
Amount Attributable to RTO and ISO Activities	0		'		519,000
Liabilities for Contracts with Cross Default Provisions Prior to Contractural Netting Arrangements	0		'		3,000
Amount of Cash Collateral Posted	0		'		0
Additional Settlement Liability if Cross Default Provision is Triggered	0		'		3,000
Derivatives and Hedging (Textuals) [Abstract]	'		'		'
Cash Collateral Received Netted Against Risk Management Assets	2,000		'		0
Cash Collateral Paid Netted Against Risk Management Liabilities	0		'		3,000
Maximum Term for Exposure to Variability of Future Cash Flows	'0 months		'		'
Risk Management Contracts [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Total Assets	370,000,000	[2],[3]	'		440,000,000	[2],[4]
Total Liabilities	178,000,000	[2],[3]	'		245,000,000	[2],[4]
Risk Management Contracts [Member] \| Appalachian Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Total Assets	29,776,000	[2],[5]	'		37,756,000	[2],[5]
Total Liabilities	12,490,000	[2],[5]	'		18,846,000	[2],[5]
Risk Management Contracts [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Total Assets	21,921,000	[2],[5]	'		26,667,000	[2],[5]
Total Liabilities	9,461,000	[2],[5]	'		13,781,000	[2],[5]
Risk Management Contracts [Member] \| Ohio Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Total Assets	3,980,000	[2],[5]	'		2,920,000	[2],[5]
Total Liabilities	0	[2],[5]	'		0	[2],[5]
Risk Management Contracts [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Total Assets	1,349,000	[2],[5]	'		1,083,000	[2],[5]
Total Liabilities	83,000	[2],[5]	'		85,000	[2],[5]
Risk Management Contracts [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Total Assets	1,907,000	[2],[5]	'		1,082,000	[2],[5]
Total Liabilities	0	[2],[5]	'		0	[2],[5]
Commodity [Member]	'		'		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	13,000,000	[1]	'		7,000,000	[1]
Hedging Liabilities	5,000,000	[1]	'		6,000,000	[1]
AOCI Gain (Loss) Net of Tax	4,000,000		'		0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	3,000,000		'		0
Derivatives and Hedging (Textuals) [Abstract]	'		'		'
Cross Default Provisions Maximum Third Party Obligation Amount	50,000,000		'		50,000,000
Commodity [Member] \| Appalachian Power Co [Member]	'		'		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	209,000	[1]	'		363,000	[1]
Hedging Liabilities	75,000	[1]	'		287,000	[1]
AOCI Gain (Loss) Net of Tax	87,000		'		94,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	87,000		'		94,000
Commodity [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	142,000	[1]	'		216,000	[1]
Hedging Liabilities	51,000	[1]	'		194,000	[1]
AOCI Gain (Loss) Net of Tax	61,000		'		46,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	61,000		'		46,000
Commodity [Member] \| Ohio Power Co [Member]	'		'		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		162,000	[1]
Hedging Liabilities	0	[1]	'		0	[1]
AOCI Gain (Loss) Net of Tax	0		'		105,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	0		'		105,000
Commodity [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		84,000	[1]
Hedging Liabilities	0	[1]	'		0	[1]
AOCI Gain (Loss) Net of Tax	0		'		57,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	0		'		57,000
Commodity [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		97,000	[1]
Hedging Liabilities	0	[1]	'		0	[1]
AOCI Gain (Loss) Net of Tax	0		'		66,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	0		'		66,000
Commodity [Member] \| Risk Management Contracts [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	442,000,000	[6]	'		347,000,000	[6]
Long-term Risk Management Assets	342,000,000	[6]	'		368,000,000	[6]
Total Assets	784,000,000	[6]	'		715,000,000	[6]
Current Risk Management Liabilities	384,000,000	[6]	'		292,000,000	[6]
Long-term Risk Management Liabilities	205,000,000	[6]	'		237,000,000	[6]
Total Liabilities	589,000,000	[6]	'		529,000,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	195,000,000	[6]	'		186,000,000	[6]
Commodity [Member] \| Risk Management Contracts [Member] \| Appalachian Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	34,483,000	[6]	'		46,431,000	[6]
Long-term Risk Management Assets	17,304,000	[6]	'		20,948,000	[6]
Total Assets	51,787,000	[6]	'		67,379,000	[6]
Current Risk Management Liabilities	24,273,000	[6]	'		37,010,000	[6]
Long-term Risk Management Liabilities	11,558,000	[6]	'		14,452,000	[6]
Total Liabilities	35,831,000	[6]	'		51,462,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	15,956,000	[6]	'		15,917,000	[6]
Commodity [Member] \| Risk Management Contracts [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	26,273,000	[6]	'		33,229,000	[6]
Long-term Risk Management Assets	11,737,000	[6]	'		14,208,000	[6]
Total Assets	38,010,000	[6]	'		47,437,000	[6]
Current Risk Management Liabilities	18,614,000	[6]	'		26,779,000	[6]
Long-term Risk Management Liabilities	7,839,000	[6]	'		9,802,000	[6]
Total Liabilities	26,453,000	[6]	'		36,581,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	11,557,000	[6]	'		10,856,000	[6]
Commodity [Member] \| Risk Management Contracts [Member] \| Ohio Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	4,066,000	[6]	'		3,269,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	4,066,000	[6]	'		3,269,000	[6]
Current Risk Management Liabilities	83,000	[6]	'		349,000	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	83,000	[6]	'		349,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	3,983,000	[6]	'		2,920,000	[6]
Commodity [Member] \| Risk Management Contracts [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	1,403,000	[6]	'		1,078,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	1,403,000	[6]	'		1,078,000	[6]
Current Risk Management Liabilities	136,000	[6]	'		81,000	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	136,000	[6]	'		81,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	1,267,000	[6]	'		997,000	[6]
Commodity [Member] \| Risk Management Contracts [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	2,080,000	[6]	'		1,233,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	2,080,000	[6]	'		1,233,000	[6]
Current Risk Management Liabilities	171,000	[6]	'		154,000	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	171,000	[6]	'		154,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	1,909,000	[6]	'		1,079,000	[6]
Commodity [Member] \| Hedging Contracts [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	23,000,000	[6]	'		12,000,000	[6]
Long-term Risk Management Assets	5,000,000	[6]	'		3,000,000	[6]
Total Assets	28,000,000	[6]	'		15,000,000	[6]
Current Risk Management Liabilities	16,000,000	[6]	'		11,000,000	[6]
Long-term Risk Management Liabilities	4,000,000	[6]	'		3,000,000	[6]
Total Liabilities	20,000,000	[6]	'		14,000,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	8,000,000	[6]	'		1,000,000	[6]
Commodity [Member] \| Hedging Contracts [Member] \| Appalachian Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	224,000	[6]	'		389,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	224,000	[6]	'		389,000	[6]
Current Risk Management Liabilities	90,000	[6]	'		313,000	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	90,000	[6]	'		313,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	134,000	[6]	'		76,000	[6]
Commodity [Member] \| Hedging Contracts [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	152,000	[6]	'		234,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	152,000	[6]	'		234,000	[6]
Current Risk Management Liabilities	61,000	[6]	'		212,000	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	61,000	[6]	'		212,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	91,000	[6]	'		22,000	[6]
Commodity [Member] \| Hedging Contracts [Member] \| Ohio Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	0	[6]	'		162,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	0	[6]	'		162,000	[6]
Current Risk Management Liabilities	0	[6]	'		0	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	0	[6]	'		0	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	0	[6]	'		162,000	[6]
Commodity [Member] \| Hedging Contracts [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	0	[6]	'		84,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	0	[6]	'		84,000	[6]
Current Risk Management Liabilities	0	[6]	'		0	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	0	[6]	'		0	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	0	[6]	'		84,000	[6]
Commodity [Member] \| Hedging Contracts [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	0	[6]	'		97,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	0	[6]	'		97,000	[6]
Current Risk Management Liabilities	0	[6]	'		0	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	0	[6]	'		0	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	0	[6]	'		97,000	[6]
Interest Rate and Foreign Currency [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	819,000,000		'		820,000,000
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		0	[1]
Hedging Liabilities	2,000,000	[1]	'		2,000,000	[1]
AOCI Gain (Loss) Net of Tax	-22,000,000		'		-23,000,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	-4,000,000		'		-4,000,000
Interest Rate and Foreign Currency [Member] \| Appalachian Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	0		'		0
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		0	[1]
Hedging Liabilities	0	[1]	'		0	[1]
AOCI Gain (Loss) Net of Tax	3,343,000		'		3,090,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	-682,000		'		-806,000
Interest Rate and Foreign Currency [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	0		'		0
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		0	[1]
Hedging Liabilities	0	[1]	'		0	[1]
AOCI Gain (Loss) Net of Tax	-15,566,000		'		-15,976,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	-1,426,000		'		-1,568,000
Interest Rate and Foreign Currency [Member] \| Ohio Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	0		'		0
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		0	[1]
Hedging Liabilities	0	[1]	'		0	[1]
AOCI Gain (Loss) Net of Tax	6,631,000		'		6,974,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	1,372,000		'		1,363,000
Interest Rate and Foreign Currency [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	0		'		0
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		0	[1]
Hedging Liabilities	0	[1]	'		0	[1]
AOCI Gain (Loss) Net of Tax	5,512,000		'		5,701,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	759,000		'		759,000
Interest Rate and Foreign Currency [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	0		'		0
Impact of Cash Flow Hedges on the Condensed Balance Sheet	'		'		'
Hedging Assets	0	[1]	'		0	[1]
Hedging Liabilities	0	[1]	'		0	[1]
AOCI Gain (Loss) Net of Tax	-12,736,000		'		-13,304,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months	-2,267,000		'		-2,267,000
Interest Rate and Foreign Currency [Member] \| Hedging Contracts [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	4,000,000	[6]	'		4,000,000	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	4,000,000	[6]	'		4,000,000	[6]
Current Risk Management Liabilities	1,000,000	[6]	'		1,000,000	[6]
Long-term Risk Management Liabilities	13,000,000	[6]	'		15,000,000	[6]
Total Liabilities	14,000,000	[6]	'		16,000,000	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	-10,000,000	[6]	'		-12,000,000	[6]
Interest Rate and Foreign Currency [Member] \| Hedging Contracts [Member] \| Appalachian Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	0	[6]	'		0	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	0	[6]	'		0	[6]
Current Risk Management Liabilities	0	[6]	'		0	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	0	[6]	'		0	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	0	[6]	'		0	[6]
Interest Rate and Foreign Currency [Member] \| Hedging Contracts [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	0	[6]	'		0	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	0	[6]	'		0	[6]
Current Risk Management Liabilities	0	[6]	'		0	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	0	[6]	'		0	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	0	[6]	'		0	[6]
Interest Rate and Foreign Currency [Member] \| Hedging Contracts [Member] \| Ohio Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	0	[6]	'		0	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	0	[6]	'		0	[6]
Current Risk Management Liabilities	0	[6]	'		0	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	0	[6]	'		0	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	0	[6]	'		0	[6]
Interest Rate and Foreign Currency [Member] \| Hedging Contracts [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	0	[6]	'		0	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	0	[6]	'		0	[6]
Current Risk Management Liabilities	0	[6]	'		0	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	0	[6]	'		0	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	0	[6]	'		0	[6]
Interest Rate and Foreign Currency [Member] \| Hedging Contracts [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	0	[6]	'		0	[6]
Long-term Risk Management Assets	0	[6]	'		0	[6]
Total Assets	0	[6]	'		0	[6]
Current Risk Management Liabilities	0	[6]	'		0	[6]
Long-term Risk Management Liabilities	0	[6]	'		0	[6]
Total Liabilities	0	[6]	'		0	[6]
Total MTM Derivative Contract Net Assets (Liabilities)	0	[6]	'		0	[6]
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	469,000,000		'		363,000,000
Long-term Risk Management Assets	347,000,000		'		371,000,000
Total Assets	816,000,000		'		734,000,000
Current Risk Management Liabilities	401,000,000		'		304,000,000
Long-term Risk Management Liabilities	222,000,000		'		255,000,000
Total Liabilities	623,000,000		'		559,000,000
Total MTM Derivative Contract Net Assets (Liabilities)	193,000,000		'		175,000,000
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] \| Appalachian Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	34,707,000		'		46,820,000
Long-term Risk Management Assets	17,304,000		'		20,948,000
Total Assets	52,011,000		'		67,768,000
Current Risk Management Liabilities	24,363,000		'		37,323,000
Long-term Risk Management Liabilities	11,558,000		'		14,452,000
Total Liabilities	35,921,000		'		51,775,000
Total MTM Derivative Contract Net Assets (Liabilities)	16,090,000		'		15,993,000
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	26,425,000		'		33,463,000
Long-term Risk Management Assets	11,737,000		'		14,208,000
Total Assets	38,162,000		'		47,671,000
Current Risk Management Liabilities	18,675,000		'		26,991,000
Long-term Risk Management Liabilities	7,839,000		'		9,802,000
Total Liabilities	26,514,000		'		36,793,000
Total MTM Derivative Contract Net Assets (Liabilities)	11,648,000		'		10,878,000
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] \| Ohio Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	4,066,000		'		3,431,000
Long-term Risk Management Assets	0		'		0
Total Assets	4,066,000		'		3,431,000
Current Risk Management Liabilities	83,000		'		349,000
Long-term Risk Management Liabilities	0		'		0
Total Liabilities	83,000		'		349,000
Total MTM Derivative Contract Net Assets (Liabilities)	3,983,000		'		3,082,000
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	1,403,000		'		1,162,000
Long-term Risk Management Assets	0		'		0
Total Assets	1,403,000		'		1,162,000
Current Risk Management Liabilities	136,000		'		81,000
Long-term Risk Management Liabilities	0		'		0
Total Liabilities	136,000		'		81,000
Total MTM Derivative Contract Net Assets (Liabilities)	1,267,000		'		1,081,000
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	2,080,000		'		1,330,000
Long-term Risk Management Assets	0		'		0
Total Assets	2,080,000		'		1,330,000
Current Risk Management Liabilities	171,000		'		154,000
Long-term Risk Management Liabilities	0		'		0
Total Liabilities	171,000		'		154,000
Total MTM Derivative Contract Net Assets (Liabilities)	1,909,000		'		1,176,000
Gross Amounts Offset in the Statement of Financial Position [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	-344,000,000	[7]	'		-203,000,000	[7]
Long-term Risk Management Assets	-81,000,000	[7]	'		-74,000,000	[7]
Total Assets	-425,000,000	[7]	'		-277,000,000	[7]
Current Risk Management Liabilities	-341,000,000	[7]	'		-214,000,000	[7]
Long-term Risk Management Liabilities	-85,000,000	[7]	'		-78,000,000	[7]
Total Liabilities	-426,000,000	[7]	'		-292,000,000	[7]
Total MTM Derivative Contract Net Assets (Liabilities)	1,000,000	[7]	'		15,000,000	[7]
Gross Amounts Offset in the Statement of Financial Position [Member] \| Appalachian Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	-18,735,000	[8]	'		-25,649,000	[8]
Long-term Risk Management Assets	-3,291,000	[8]	'		-4,000,000	[8]
Total Assets	-22,026,000	[8]	'		-29,649,000	[8]
Current Risk Management Liabilities	-19,727,000	[8]	'		-28,431,000	[8]
Long-term Risk Management Liabilities	-3,629,000	[8]	'		-4,211,000	[8]
Total Liabilities	-23,356,000	[8]	'		-32,642,000	[8]
Total MTM Derivative Contract Net Assets (Liabilities)	1,330,000	[8]	'		2,993,000	[8]
Gross Amounts Offset in the Statement of Financial Position [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	-13,867,000	[8]	'		-18,075,000	[8]
Long-term Risk Management Assets	-2,232,000	[8]	'		-2,713,000	[8]
Total Assets	-16,099,000	[8]	'		-20,788,000	[8]
Current Risk Management Liabilities	-14,541,000	[8]	'		-19,962,000	[8]
Long-term Risk Management Liabilities	-2,461,000	[8]	'		-2,856,000	[8]
Total Liabilities	-17,002,000	[8]	'		-22,818,000	[8]
Total MTM Derivative Contract Net Assets (Liabilities)	903,000	[8]	'		2,030,000	[8]
Gross Amounts Offset in the Statement of Financial Position [Member] \| Ohio Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	-86,000	[8]	'		-349,000	[8]
Long-term Risk Management Assets	0	[8]	'		0	[8]
Total Assets	-86,000	[8]	'		-349,000	[8]
Current Risk Management Liabilities	-83,000	[8]	'		-349,000	[8]
Long-term Risk Management Liabilities	0	[8]	'		0	[8]
Total Liabilities	-83,000	[8]	'		-349,000	[8]
Total MTM Derivative Contract Net Assets (Liabilities)	-3,000	[8]	'		0	[8]
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	-54,000	[8]	'		5,000	[8]
Long-term Risk Management Assets	0	[8]	'		0	[8]
Total Assets	-54,000	[8]	'		5,000	[8]
Current Risk Management Liabilities	-53,000	[8]	'		4,000	[8]
Long-term Risk Management Liabilities	0	[8]	'		0	[8]
Total Liabilities	-53,000	[8]	'		4,000	[8]
Total MTM Derivative Contract Net Assets (Liabilities)	-1,000	[8]	'		1,000	[8]
Gross Amounts Offset in the Statement of Financial Position [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	-173,000	[8]	'		-151,000	[8]
Long-term Risk Management Assets	0	[8]	'		0	[8]
Total Assets	-173,000	[8]	'		-151,000	[8]
Current Risk Management Liabilities	-171,000	[8]	'		-154,000	[8]
Long-term Risk Management Liabilities	0	[8]	'		0	[8]
Total Liabilities	-171,000	[8]	'		-154,000	[8]
Total MTM Derivative Contract Net Assets (Liabilities)	-2,000	[8]	'		3,000	[8]
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	125,000,000	[9]	'		160,000,000	[9]
Long-term Risk Management Assets	266,000,000	[9]	'		297,000,000	[9]
Total Assets	391,000,000	[9]	'		457,000,000	[9]
Current Risk Management Liabilities	60,000,000	[9]	'		90,000,000	[9]
Long-term Risk Management Liabilities	137,000,000	[9]	'		177,000,000	[9]
Total Liabilities	197,000,000	[9]	'		267,000,000	[9]
Total MTM Derivative Contract Net Assets (Liabilities)	194,000,000	[9]	'		190,000,000	[9]
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	15,972,000	[9]	'		21,171,000	[9]
Long-term Risk Management Assets	14,013,000	[9]	'		16,948,000	[9]
Total Assets	29,985,000	[9]	'		38,119,000	[9]
Current Risk Management Liabilities	4,636,000	[9]	'		8,892,000	[9]
Long-term Risk Management Liabilities	7,929,000	[9]	'		10,241,000	[9]
Total Liabilities	12,565,000	[9]	'		19,133,000	[9]
Total MTM Derivative Contract Net Assets (Liabilities)	17,420,000	[9]	'		18,986,000	[9]
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	12,558,000	[9]	'		15,388,000	[9]
Long-term Risk Management Assets	9,505,000	[9]	'		11,495,000	[9]
Total Assets	22,063,000	[9]	'		26,883,000	[9]
Current Risk Management Liabilities	4,134,000	[9]	'		7,029,000	[9]
Long-term Risk Management Liabilities	5,378,000	[9]	'		6,946,000	[9]
Total Liabilities	9,512,000	[9]	'		13,975,000	[9]
Total MTM Derivative Contract Net Assets (Liabilities)	12,551,000	[9]	'		12,908,000	[9]
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	3,980,000	[9]	'		3,082,000	[9]
Long-term Risk Management Assets	0	[9]	'		0	[9]
Total Assets	3,980,000	[9]	'		3,082,000	[9]
Current Risk Management Liabilities	0	[9]	'		0	[9]
Long-term Risk Management Liabilities	0	[9]	'		0	[9]
Total Liabilities	0	[9]	'		0	[9]
Total MTM Derivative Contract Net Assets (Liabilities)	3,980,000	[9]	'		3,082,000	[9]
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	1,349,000	[9]	'		1,167,000	[9]
Long-term Risk Management Assets	0	[9]	'		0	[9]
Total Assets	1,349,000	[9]	'		1,167,000	[9]
Current Risk Management Liabilities	83,000	[9]	'		85,000	[9]
Long-term Risk Management Liabilities	0	[9]	'		0	[9]
Total Liabilities	83,000	[9]	'		85,000	[9]
Total MTM Derivative Contract Net Assets (Liabilities)	1,266,000	[9]	'		1,082,000	[9]
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Fair Value of Derivative Instruments	'		'		'
Current Risk Management Assets	1,907,000	[9]	'		1,179,000	[9]
Long-term Risk Management Assets	0	[9]	'		0	[9]
Total Assets	1,907,000	[9]	'		1,179,000	[9]
Current Risk Management Liabilities	0	[9]	'		0	[9]
Long-term Risk Management Liabilities	0	[9]	'		0	[9]
Total Liabilities	0	[9]	'		0	[9]
Total MTM Derivative Contract Net Assets (Liabilities)	1,907,000	[9]	'		1,179,000	[9]
Power [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	320,000,000		'		406,000,000
Power [Member] \| Appalachian Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	29,680,000		'		48,995,000
Power [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	19,636,000		'		33,231,000
Power [Member] \| Ohio Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	12,108,000		'		34,843,000
Power [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	9,251,000		'		13,469,000
Power [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	11,716,000		'		17,057,000
Coal [Member]	'		'		'
Commodity	'		'		'
Derivative, Mass Notional Amount	4,000,000		'		4,000,000
Coal [Member] \| Appalachian Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Mass Notional Amount	186,000		'		31,000
Coal [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Mass Notional Amount	2,666,000		'		3,389,000
Coal [Member] \| Ohio Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Mass Notional Amount	0		'		0
Coal [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Commodity	'		'		'
Derivative, Mass Notional Amount	750,000		'		1,013,000
Coal [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Mass Notional Amount	1,292,000		'		1,692,000
Natural Gas [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	123,000,000		'		127,000,000
Natural Gas [Member] \| Appalachian Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	1,934,000		'		2,477,000
Natural Gas [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	1,312,000		'		1,680,000
Natural Gas [Member] \| Ohio Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	0		'		0
Natural Gas [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	0		'		0
Natural Gas [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Energy Notional Amount	0		'		0
Heating Oil and Gasoline [Member]	'		'		'
Commodity	'		'		'
Derivative, Volume Notional Amount	4,000,000		'		6,000,000
Heating Oil and Gasoline [Member] \| Appalachian Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Volume Notional Amount	792,000		'		1,089,000
Heating Oil and Gasoline [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Volume Notional Amount	379,000		'		521,000
Heating Oil and Gasoline [Member] \| Ohio Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Volume Notional Amount	806,000		'		1,108,000
Heating Oil and Gasoline [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Commodity	'		'		'
Derivative, Volume Notional Amount	446,000		'		614,000
Heating Oil and Gasoline [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Volume Notional Amount	508,000		'		699,000
Interest Rate Contract [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	192,000,000		'		191,000,000
Interest Rate Contract [Member] \| Appalachian Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	10,877,000		'		12,720,000
Interest Rate Contract [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Commodity	'		'		'
Derivative, Notional Amount	7,378,000		'		8,627,000
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	18,000,000		6,000,000		'
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	4,847,000		679,000		'
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	6,156,000		4,947,000		'
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		1,714,000		'
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	64,000		47,000		'
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	23,000		28,000		'
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	0		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	-221,000		0		'
Sales to AEP Affiliates [Member] \| Ohio Power Co [Member]	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	0		0		'
Sales to AEP Affiliates [Member] \| Public Service Co Of Oklahoma [Member]	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	221,000		0		'
Sales to AEP Affiliates [Member] \| Southwestern Electric Power Co [Member]	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	0		0		'
Generation And Marketing Revenues [Member]	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	32,000,000		16,000,000		'
Regulatory Assets [Member]	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	0	[10]	2,000,000	[10]	'
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	4,000	[10]	0	[10]	'
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	0	[10]	486,000	[10]	'
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	0	[10]	-1,205,000	[10]	'
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	2,000	[10]	2,010,000	[10]	'
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	3,000	[10]	271,000	[10]	'
Regulatory Liabilities [Member]	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	'		'		'
Amount of Gain (Loss) Recognized on Risk Management Contracts	89,000,000	[10]	-6,000,000	[10]	'
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	32,332,000	[10]	-466,000	[10]	'
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	18,317,000	[10]	-5,182,000	[10]	'
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	35,099,000	[10]	0	[10]	'
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	480,000	[10]	1,000	[10]	'
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	$1,330,000	[10]	$96,000	[10]	'

[1]	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
[2]	Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''
[3]	The March 31, 2014 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 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.
[4]	The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.
[5]	Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
[6]	Derivative instruments within these categories are reported gross. These instruments are subject to master netting agreements and are presented on the condensed balance sheets on a net basis in accordance with the accounting guidance for "Derivatives and Hedging."
[7]	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." Amounts also include de-designated risk management contracts.
[8]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
[9]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[10]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

Fair_Value_Longterm_Debt_Other

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) (USD $)	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013	Dec. 31, 2013
Book Values and Fair Values of Long - term Debt	'		'	'
Total Long-term Debt Outstanding	$18,087,000,000		'	$18,377,000,000
Long Term Debt, Fair Value	19,738,000,000		'	19,672,000,000
Other Temporary Investments	'		'	'
Cost	299,000,000		'	342,000,000
Gross Unrealized Gains	11,000,000		'	11,000,000
Gross Unrealized Losses	0		'	0
Estimated Fair Value	310,000,000		'	353,000,000
Debt and Equity Securities Within Other Temporary Investments [Abstract]	'		'	'
Proceeds from Investment Sales	0		0	'
Purchases of Investments	1,000,000		11,000,000	'
Gross Realized Gains on Investment Sales	0		0	'
Gross Realized Losses on Investment Sales	0		0	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	1,962,000,000		'	1,932,000,000
Gross Unrealized Gains	550,000,000		'	535,000,000
Other-Than-Temporary Impairments	85,000,000		'	87,000,000
Securities Activity Within Decommissioning and SNF Trusts [Abstract]	'		'	'
Proceeds from Investment Sales	148,000,000		168,000,000	'
Purchases of Investments	164,000,000		185,000,000	'
Gross Realized Gains on Investment Sales	8,000,000		3,000,000	'
Gross Realized Losses on Investment Sales	1,000,000		2,000,000	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	1,962,000,000		'	1,932,000,000
Fair Value Measurements (Textuals) [Abstract]	'		'	'
Adjusted Cost of Debt Securities	894,000,000		'	872,000,000
Adjusted Cost of Domestic Equity Securities	506,000,000		'	506,000,000
Appalachian Power Co [Member]	'		'	'
Book Values and Fair Values of Long - term Debt	'		'	'
Total Long-term Debt Outstanding	4,194,516,000		'	4,194,357,000
Long Term Debt, Fair Value	4,730,819,000		'	4,587,079,000
Indiana Michigan Power Co [Member]	'		'	'
Book Values and Fair Values of Long - term Debt	'		'	'
Total Long-term Debt Outstanding	2,012,844,000		'	2,039,016,000
Long Term Debt, Fair Value	2,203,640,000		'	2,174,891,000
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	1,962,151,000		'	1,931,610,000
Gross Unrealized Gains	549,664,000		'	534,850,000
Other-Than-Temporary Impairments	84,626,000		'	86,994,000
Securities Activity Within Decommissioning and SNF Trusts [Abstract]	'		'	'
Proceeds from Investment Sales	147,700,000		167,670,000	'
Purchases of Investments	164,511,000		184,299,000	'
Gross Realized Gains on Investment Sales	8,141,000		3,323,000	'
Gross Realized Losses on Investment Sales	874,000		2,315,000	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	1,962,151,000		'	1,931,610,000
Fair Value Measurements (Textuals) [Abstract]	'		'	'
Adjusted Cost of Debt Securities	894,000,000		'	872,000,000
Adjusted Cost of Domestic Equity Securities	506,000,000		'	506,000,000
Ohio Power Co [Member]	'		'	'
Book Values and Fair Values of Long - term Debt	'		'	'
Total Long-term Debt Outstanding	2,510,285,000		'	2,735,175,000
Long Term Debt, Fair Value	2,869,364,000		'	3,007,191,000
Public Service Co Of Oklahoma [Member]	'		'	'
Book Values and Fair Values of Long - term Debt	'		'	'
Total Long-term Debt Outstanding	1,049,793,000		'	999,810,000
Long Term Debt, Fair Value	1,200,741,000		'	1,111,149,000
Southwestern Electric Power Co [Member]	'		'	'
Book Values and Fair Values of Long - term Debt	'		'	'
Total Long-term Debt Outstanding	2,041,796,000		'	2,043,332,000
Long Term Debt, Fair Value	2,277,262,000		'	2,214,730,000
Cash [Member]	'		'	'
Other Temporary Investments	'		'	'
Cost	206,000,000		'	250,000,000
Gross Unrealized Gains	0		'	0
Gross Unrealized Losses	0		'	0
Estimated Fair Value	206,000,000	[1]	'	250,000,000	[1]
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	12,000,000	[2]	'	19,000,000	[2]
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	12,000,000	[2]	'	19,000,000	[2]
Cash [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	12,439,000	[3]	'	18,804,000	[3]
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	12,439,000	[3]	'	18,804,000	[3]
Fixed Income Funds [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	930,000,000		'	901,000,000
Gross Unrealized Gains	36,000,000		'	29,000,000
Other-Than-Temporary Impairments	5,000,000		'	5,000,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	930,000,000		'	901,000,000
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	929,567,000		'	900,295,000
Gross Unrealized Gains	35,861,000		'	29,312,000
Other-Than-Temporary Impairments	5,063,000		'	5,317,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	929,567,000		'	900,295,000
Mutual Funds Fixed Income [Member]	'		'	'
Other Temporary Investments	'		'	'
Cost	80,000,000		'	80,000,000
Gross Unrealized Gains	0		'	0
Gross Unrealized Losses	0		'	0
Estimated Fair Value	80,000,000		'	80,000,000
Domestic [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	1,020,000,000	[4]	'	1,012,000,000	[4]
Gross Unrealized Gains	514,000,000		'	506,000,000
Other-Than-Temporary Impairments	80,000,000		'	82,000,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	1,020,000,000	[4]	'	1,012,000,000	[4]
Domestic [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	1,020,145,000	[4]	'	1,012,511,000	[4]
Gross Unrealized Gains	513,803,000		'	505,538,000
Other-Than-Temporary Impairments	79,563,000		'	81,677,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	1,020,145,000	[4]	'	1,012,511,000	[4]
Mutual Funds Equity [Member]	'		'	'
Other Temporary Investments	'		'	'
Cost	13,000,000		'	12,000,000
Gross Unrealized Gains	11,000,000		'	11,000,000
Gross Unrealized Losses	0		'	0
Estimated Fair Value	24,000,000	[4]	'	23,000,000	[4]
Cash and Cash Equivalents [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	12,000,000		'	19,000,000
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	12,000,000		'	19,000,000
Cash and Cash Equivalents [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	12,439,000		'	18,804,000
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	12,439,000		'	18,804,000
US Government Agencies Debt Securities [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	606,000,000		'	609,000,000
Gross Unrealized Gains	31,000,000		'	26,000,000
Other-Than-Temporary Impairments	4,000,000		'	4,000,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	606,000,000		'	609,000,000
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	606,228,000		'	608,875,000
Gross Unrealized Gains	31,666,000		'	26,114,000
Other-Than-Temporary Impairments	3,621,000		'	3,824,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	606,228,000		'	608,875,000
Corporate Debt [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	43,000,000		'	37,000,000
Gross Unrealized Gains	4,000,000		'	2,000,000
Other-Than-Temporary Impairments	1,000,000		'	1,000,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	43,000,000		'	37,000,000
Corporate Debt [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	42,727,000		'	36,782,000
Gross Unrealized Gains	3,223,000		'	2,450,000
Other-Than-Temporary Impairments	1,097,000		'	1,123,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	42,727,000		'	36,782,000
State and Local Jurisdiction [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	281,000,000		'	255,000,000
Gross Unrealized Gains	1,000,000		'	1,000,000
Other-Than-Temporary Impairments	0		'	0
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	281,000,000		'	255,000,000
State and Local Jurisdiction [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	280,612,000		'	254,638,000
Gross Unrealized Gains	972,000		'	748,000
Other-Than-Temporary Impairments	345,000		'	370,000
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	280,612,000		'	254,638,000
Within One Year [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	82,000,000		'	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	82,000,000		'	'
Within One Year [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	82,190,000		'	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	82,190,000		'	'
One Year To Five Year [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	386,000,000		'	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	386,000,000		'	'
One Year To Five Year [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	386,173,000		'	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	386,173,000		'	'
Five Year To Ten Year [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	193,000,000		'	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	193,000,000		'	'
Five Year To Ten Year [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	193,018,000		'	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	193,018,000		'	'
After Ten Year [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	269,000,000		'	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	269,000,000		'	'
After Ten Year [Member] \| Indiana Michigan Power Co [Member]	'		'	'
Nuclear Trust Fund Investments [Abstract]	'		'	'
Estimated Fair Value	268,186,000		'	'
Contractual Maturities, Fair Value of Debt Securities	'		'	'
Contractual Maturities, Fair Value of Debt Securities	$268,186,000		'	'

[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]	Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[3]	Amounts in bOtherb column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[4]	Amounts represent publicly traded equity securities and equity-based mutual funds.

Fair_Value_Assets_and_Liabilit

Fair Value Assets and Liabilities (Details) (USD $)	3 Months Ended				12 Months Ended
Fair Value Assets and Liabilities (Details) (USD $)	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Assets:	'		'		'
Cash and Cash Equivalents	$292,000,000	[1]	'		$118,000,000	[1]
Other Temporary Investments	310,000,000		'		353,000,000
Risk Management Assets	'		'		'
Risk Management Assets	391,000,000		'		457,000,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	1,962,000,000		'		1,932,000,000
Total Assets	2,955,000,000		'		2,860,000,000
Liabilities:	'		'		'
Risk Management Liabilities	197,000,000		'		267,000,000
Changes in the Fair Value of Net Trading Derivatives and other investments	'		'		'
Beginning Balance	117,000,000		86,000,000		86,000,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	84,000,000	[2],[3]	-4,000,000	[2],[3]	'
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	-10,000,000	[2]	-5,000,000	[2]	'
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	9,000,000		1,000,000		'
Purchases, Issuances and Settlements	-100,000,000	[4]	-6,000,000	[4]	'
Transfers into Level 3	-4,000,000	[5],[6]	6,000,000	[5],[6]	'
Transfers out of Level 3	-2,000,000	[6],[7]	0	[6],[7]	'
Changes in Fair Value Allocated to Regulated Jurisdictions	11,000,000	[8]	-2,000,000	[8]	'
Ending Balance	105,000,000		76,000,000		117,000,000
Level 3 Quantitative Information [Abstract]	'		'		'
Significant Unobservable Input Counterparty Credit Risk	3.15%	[9]	'		3.16%	[9]
Level 1 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	16,000,000	[1]	'		16,000,000	[1]
Other Temporary Investments	291,000,000		'		334,000,000
Risk Management Assets	'		'		'
Risk Management Assets	20,000,000		'		22,000,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	1,023,000,000		'		1,020,000,000
Total Assets	1,350,000,000		'		1,392,000,000
Liabilities:	'		'		'
Risk Management Liabilities	30,000,000		'		30,000,000
Level 2 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	1,000,000	[1]	'		1,000,000	[1]
Other Temporary Investments	7,000,000		'		8,000,000
Risk Management Assets	'		'		'
Risk Management Assets	609,000,000		'		565,000,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	930,000,000		'		901,000,000
Total Assets	1,547,000,000		'		1,475,000,000
Liabilities:	'		'		'
Risk Management Liabilities	512,000,000		'		499,000,000
Level 3 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	0	[1]	'		0	[1]
Other Temporary Investments	0		'		0
Risk Management Assets	'		'		'
Risk Management Assets	130,000,000		'		142,000,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Total Assets	130,000,000		'		142,000,000
Liabilities:	'		'		'
Risk Management Liabilities	25,000,000		'		25,000,000
Fair Value Inputs Other [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	275,000,000	[1]	'		101,000,000	[1]
Other Temporary Investments	12,000,000		'		11,000,000
Risk Management Assets	'		'		'
Risk Management Assets	-368,000,000		'		-272,000,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	9,000,000		'		11,000,000
Total Assets	-72,000,000		'		-149,000,000
Liabilities:	'		'		'
Risk Management Liabilities	-370,000,000		'		-287,000,000
2014 [Member] \| Level 1 [Member]	'		'		'
Fair Value Measurements 1 (Textuals) [Abstract]	'		'		'
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities	2,000,000		'		4,000,000
2014 [Member] \| Level 2 [Member]	'		'		'
Fair Value Measurements 1 (Textuals) [Abstract]	'		'		'
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities	32,000,000		'		25,000,000
2014 [Member] \| Level 3 [Member]	'		'		'
Fair Value Measurements 1 (Textuals) [Abstract]	'		'		'
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities	15,000,000		'		27,000,000
2015 - 2017 [Member] \| Level 1 [Member]	'		'		'
Fair Value Measurements 1 (Textuals) [Abstract]	'		'		'
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities	-11,000,000		'		-11,000,000
2015 - 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/Liabilities	56,000,000		'		37,000,000
2015 - 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/Liabilities	49,000,000		'		60,000,000
2018 - 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/Liabilities	-1,000,000		'		-1,000,000
2018 - 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/Liabilities	8,000,000		'		7,000,000
2018 - 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/Liabilities	16,000,000		'		14,000,000
2020 - 2030 [Member] \| Level 2 [Member]	'		'		'
Fair Value Measurements 1 (Textuals) [Abstract]	'		'		'
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities	5,000,000		'		5,000,000
2020 - 2030 [Member] \| Level 3 [Member]	'		'		'
Fair Value Measurements 1 (Textuals) [Abstract]	'		'		'
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities	23,000,000		'		19,000,000
Risk Management Commodity Contracts [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	370,000,000	[10],[11]	'		440,000,000	[10],[12]
Liabilities:	'		'		'
Risk Management Liabilities	178,000,000	[10],[11]	'		245,000,000	[10],[12]
Risk Management Commodity Contracts [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	20,000,000	[10],[11]	'		22,000,000	[10],[12]
Liabilities:	'		'		'
Risk Management Liabilities	30,000,000	[10],[11]	'		30,000,000	[10],[12]
Risk Management Commodity Contracts [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	586,000,000	[10],[11]	'		549,000,000	[10],[12]
Liabilities:	'		'		'
Risk Management Liabilities	485,000,000	[10],[11]	'		475,000,000	[10],[12]
Risk Management Commodity Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	128,000,000	[10],[11]	'		142,000,000	[10],[12]
Liabilities:	'		'		'
Risk Management Liabilities	25,000,000	[10],[11]	'		22,000,000	[10],[12]
Risk Management Commodity Contracts [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-364,000,000	[10],[11]	'		-273,000,000	[10],[12]
Liabilities:	'		'		'
Risk Management Liabilities	-362,000,000	[10],[11]	'		-282,000,000	[10],[12]
Energy Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	116,000,000		'		132,000,000
Liabilities:	'		'		'
Risk Management Liabilities	23,000,000		'		22,000,000
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	1.45	[13]	'		11.42	[13]
Forward Price Range High	131.46	[13]	'		120.72	[13]
FTRs [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	14,000,000		'		10,000,000
Liabilities:	'		'		'
Risk Management Liabilities	2,000,000		'		3,000,000
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	-5.05	[13]	'		-5.1	[13]
Forward Price Range High	9.17	[13]	'		10.44	[13]
Commodity Hedges [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	13,000,000	[10]	'		7,000,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	5,000,000	[10]	'		6,000,000	[10]
Commodity Hedges [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[10]	'		0	[10]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10]	'		0	[10]
Commodity Hedges [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	21,000,000	[10]	'		15,000,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	15,000,000	[10]	'		11,000,000	[10]
Commodity Hedges [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	2,000,000	[10]	'		0	[10]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10]	'		3,000,000	[10]
Commodity Hedges [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-10,000,000	[10]	'		-8,000,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	-10,000,000	[10]	'		-8,000,000	[10]
Interest Rate Foreign Currency Hedges [Member]	'		'		'
Liabilities:	'		'		'
Risk Management Liabilities	2,000,000		'		2,000,000
Interest Rate Foreign Currency Hedges [Member] \| Level 1 [Member]	'		'		'
Liabilities:	'		'		'
Risk Management Liabilities	0		'		0
Interest Rate Foreign Currency Hedges [Member] \| Level 2 [Member]	'		'		'
Liabilities:	'		'		'
Risk Management Liabilities	2,000,000		'		2,000,000
Interest Rate Foreign Currency Hedges [Member] \| Level 3 [Member]	'		'		'
Liabilities:	'		'		'
Risk Management Liabilities	0		'		0
Interest Rate Foreign Currency Hedges [Member] \| Fair Value Inputs Other [Member]	'		'		'
Liabilities:	'		'		'
Risk Management Liabilities	0		'		0
Fair Value Hedges [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	4,000,000		'		4,000,000
Liabilities:	'		'		'
Risk Management Liabilities	12,000,000		'		14,000,000
Fair Value Hedges [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0		'		0
Liabilities:	'		'		'
Risk Management Liabilities	0		'		0
Fair Value Hedges [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	2,000,000		'		1,000,000
Liabilities:	'		'		'
Risk Management Liabilities	10,000,000		'		11,000,000
Fair Value Hedges [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0		'		0
Liabilities:	'		'		'
Risk Management Liabilities	0		'		0
Fair Value Hedges [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	2,000,000		'		3,000,000
Liabilities:	'		'		'
Risk Management Liabilities	2,000,000		'		3,000,000
Appalachian Power Co [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	13,572,000	[1]	'		2,750,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	29,985,000		'		38,119,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	43,557,000		'		40,869,000
Liabilities:	'		'		'
Risk Management Liabilities	12,565,000		'		19,133,000
Changes in the Fair Value of Net Trading Derivatives and other investments	'		'		'
Beginning Balance	10,562,000		10,979,000		10,979,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	29,162,000	[2],[3]	-1,456,000	[2],[3]	'
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	0	[2]	0	[2]	'
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	0		0		'
Purchases, Issuances and Settlements	-31,781,000	[4]	257,000	[4]	'
Transfers into Level 3	-3,825,000	[5],[6]	632,000	[5],[6]	'
Transfers out of Level 3	-6,000	[6],[7]	-533,000	[6],[7]	'
Changes in Fair Value Allocated to Regulated Jurisdictions	3,289,000	[8]	-1,123,000	[8]	'
Ending Balance	7,401,000		8,756,000		'
Appalachian Power Co [Member] \| Level 1 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	13,536,000	[1]	'		2,714,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	393,000		'		827,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	13,929,000		'		3,541,000
Liabilities:	'		'		'
Risk Management Liabilities	306,000		'		700,000
Appalachian Power Co [Member] \| Level 2 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	0	[1]	'		0	[1]
Risk Management Assets	'		'		'
Risk Management Assets	38,078,000		'		54,837,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	38,078,000		'		54,837,000
Liabilities:	'		'		'
Risk Management Liabilities	29,476,000		'		49,533,000
Appalachian Power Co [Member] \| Level 3 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	0	[1]	'		0	[1]
Risk Management Assets	'		'		'
Risk Management Assets	10,508,000		'		12,097,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	10,508,000		'		12,097,000
Liabilities:	'		'		'
Risk Management Liabilities	3,107,000		'		1,535,000
Appalachian Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	36,000	[1]	'		36,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	-18,994,000		'		-29,642,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	-18,958,000		'		-29,606,000
Liabilities:	'		'		'
Risk Management Liabilities	-20,324,000		'		-32,635,000
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	29,776,000	[10],[14]	'		37,756,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	12,490,000	[10],[14]	'		18,846,000	[10],[14]
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	393,000	[10],[14]	'		827,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	306,000	[10],[14]	'		700,000	[10],[14]
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	37,854,000	[10],[14]	'		54,448,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	29,386,000	[10],[14]	'		49,220,000	[10],[14]
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	10,508,000	[10],[14]	'		12,097,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	3,107,000	[10],[14]	'		1,535,000	[10],[14]
Appalachian Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-18,979,000	[10],[14]	'		-29,616,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	-20,309,000	[10],[14]	'		-32,609,000	[10],[14]
Appalachian Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	6,454,000		'		9,359,000
Liabilities:	'		'		'
Risk Management Liabilities	2,822,000		'		960,000
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	13.34		'		13.04
Forward Price Range High	59.6		'		80.5
Appalachian Power Co [Member] \| FTRs [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	4,054,000		'		2,738,000
Liabilities:	'		'		'
Risk Management Liabilities	285,000		'		575,000
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	-5.05		'		-5.1
Forward Price Range High	9.17		'		10.44
Appalachian Power Co [Member] \| Commodity Hedges [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	209,000	[10]	'		363,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	75,000	[10]	'		287,000	[10]
Appalachian Power Co [Member] \| Commodity Hedges [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[10]	'		0	[10]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10]	'		0	[10]
Appalachian Power Co [Member] \| Commodity Hedges [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	224,000	[10]	'		389,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	90,000	[10]	'		313,000	[10]
Appalachian Power Co [Member] \| Commodity Hedges [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[10]	'		0	[10]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10]	'		0	[10]
Appalachian Power Co [Member] \| Commodity Hedges [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-15,000	[10]	'		-26,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	-15,000	[10]	'		-26,000	[10]
Indiana Michigan Power Co [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	22,063,000		'		26,883,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	1,962,151,000		'		1,931,610,000
Total Assets	1,984,214,000		'		1,958,493,000
Liabilities:	'		'		'
Risk Management Liabilities	9,512,000		'		13,975,000
Changes in the Fair Value of Net Trading Derivatives and other investments	'		'		'
Beginning Balance	7,164,000		7,541,000		7,541,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	18,219,000	[2],[3]	-1,005,000	[2],[3]	'
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	0	[2]	0	[2]	'
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	0		0		'
Purchases, Issuances and Settlements	-19,995,000	[4]	179,000	[4]	'
Transfers into Level 3	-2,594,000	[5],[6]	434,000	[5],[6]	'
Transfers out of Level 3	-4,000	[6],[7]	-366,000	[6],[7]	'
Changes in Fair Value Allocated to Regulated Jurisdictions	2,052,000	[8]	-732,000	[8]	'
Ending Balance	4,842,000		6,051,000		'
Indiana Michigan Power Co [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	267,000		'		561,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	1,023,721,000		'		1,020,593,000
Total Assets	1,023,988,000		'		1,021,154,000
Liabilities:	'		'		'
Risk Management Liabilities	208,000		'		475,000
Indiana Michigan Power Co [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	28,898,000		'		38,901,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	929,567,000		'		900,295,000
Total Assets	958,465,000		'		939,196,000
Liabilities:	'		'		'
Risk Management Liabilities	22,150,000		'		35,273,000
Indiana Michigan Power Co [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	6,945,000		'		8,205,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Total Assets	6,945,000		'		8,205,000
Liabilities:	'		'		'
Risk Management Liabilities	2,104,000		'		1,041,000
Indiana Michigan Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-14,047,000		'		-20,784,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	8,863,000		'		10,722,000
Total Assets	-5,184,000		'		-10,062,000
Liabilities:	'		'		'
Risk Management Liabilities	-14,950,000		'		-22,814,000
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	21,921,000	[10],[14]	'		26,667,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	9,461,000	[10],[14]	'		13,781,000	[10],[14]
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	267,000	[10],[14]	'		561,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	208,000	[10],[14]	'		475,000	[10],[14]
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	28,746,000	[10],[14]	'		38,667,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	22,089,000	[10],[14]	'		35,061,000	[10],[14]
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	6,945,000	[10],[14]	'		8,205,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	2,104,000	[10],[14]	'		1,041,000	[10],[14]
Indiana Michigan Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-14,037,000	[10],[14]	'		-20,766,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	-14,940,000	[10],[14]	'		-22,796,000	[10],[14]
Indiana Michigan Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	4,378,000		'		6,348,000
Liabilities:	'		'		'
Risk Management Liabilities	1,914,000		'		651,000
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	13.34		'		13.04
Forward Price Range High	59.6		'		80.5
Indiana Michigan Power Co [Member] \| FTRs [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	2,567,000		'		1,857,000
Liabilities:	'		'		'
Risk Management Liabilities	190,000		'		390,000
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	-5.05		'		-5.1
Forward Price Range High	9.17		'		10.44
Indiana Michigan Power Co [Member] \| Commodity Hedges [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	142,000	[10]	'		216,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	51,000	[10]	'		194,000	[10]
Indiana Michigan Power Co [Member] \| Commodity Hedges [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[10]	'		0	[10]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10]	'		0	[10]
Indiana Michigan Power Co [Member] \| Commodity Hedges [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	152,000	[10]	'		234,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	61,000	[10]	'		212,000	[10]
Indiana Michigan Power Co [Member] \| Commodity Hedges [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[10]	'		0	[10]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10]	'		0	[10]
Indiana Michigan Power Co [Member] \| Commodity Hedges [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-10,000	[10]	'		-18,000	[10]
Liabilities:	'		'		'
Risk Management Liabilities	-10,000	[10]	'		-18,000	[10]
Ohio Power Co [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	32,066,000	[1]	'		19,399,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		3,082,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	36,046,000		'		22,481,000
Changes in the Fair Value of Net Trading Derivatives and other investments	'		'		'
Beginning Balance	2,920,000		15,429,000		15,429,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	30,963,000	[2],[3]	-2,055,000	[2],[3]	'
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	0	[2]	-1,988,000	[2]	'
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	0		0		'
Purchases, Issuances and Settlements	-34,036,000	[4]	366,000	[4]	'
Transfers into Level 3	0	[5],[6]	888,000	[5],[6]	'
Transfers out of Level 3	0	[6],[7]	-749,000	[6],[7]	'
Changes in Fair Value Allocated to Regulated Jurisdictions	4,065,000	[8]	490,000	[8]	'
Ending Balance	3,912,000		12,381,000		'
Ohio Power Co [Member] \| Level 1 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	32,054,000	[1]	'		19,387,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	32,054,000		'		19,387,000
Ohio Power Co [Member] \| Level 2 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	0	[1]	'		0	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		162,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	76,000		'		162,000
Ohio Power Co [Member] \| Level 3 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	0	[1]	'		0	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		3,269,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	3,990,000		'		3,269,000
Ohio Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	12,000	[1]	'		12,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		-349,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	-74,000		'		-337,000
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	3,980,000	[10],[14]	'		2,920,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10],[14]	'		0	[10],[14]
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[10],[14]	'		0	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10],[14]	'		0	[10],[14]
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	76,000	[10],[14]	'		0	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	5,000	[10],[14]	'		0	[10],[14]
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	3,990,000	[10],[14]	'		3,269,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	78,000	[10],[14]	'		349,000	[10],[14]
Ohio Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-86,000	[10],[14]	'		-349,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	-83,000	[10],[14]	'		-349,000	[10],[14]
Ohio Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0		'		0
Liabilities:	'		'		'
Risk Management Liabilities	0		'		0
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	0		'		0
Forward Price Range High	0		'		0
Ohio Power Co [Member] \| FTRs [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	3,990,000		'		3,269,000
Liabilities:	'		'		'
Risk Management Liabilities	78,000		'		349,000
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	-5.05		'		-5.1
Forward Price Range High	9.17		'		10.44
Ohio Power Co [Member] \| Commodity Hedges [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		162,000	[10]
Ohio Power Co [Member] \| Commodity Hedges [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Ohio Power Co [Member] \| Commodity Hedges [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		162,000	[10]
Ohio Power Co [Member] \| Commodity Hedges [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Ohio Power Co [Member] \| Commodity Hedges [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Public Service Co Of Oklahoma [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		1,167,000
Changes in the Fair Value of Net Trading Derivatives and other investments	'		'		'
Beginning Balance	0		0		0
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	0	[2],[3]	0	[2],[3]	'
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	0	[2]	0	[2]	'
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	0		0		'
Purchases, Issuances and Settlements	0	[4]	0	[4]	'
Transfers into Level 3	0	[5],[6]	0	[5],[6]	'
Transfers out of Level 3	0	[6],[7]	0	[6],[7]	'
Changes in Fair Value Allocated to Regulated Jurisdictions	349,000	[8]	0	[8]	'
Ending Balance	349,000		0		'
Public Service Co Of Oklahoma [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0
Public Service Co Of Oklahoma [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		1,162,000
Public Service Co Of Oklahoma [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0
Public Service Co Of Oklahoma [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		5,000
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	1,349,000	[10],[14]	'		1,083,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	83,000	[10],[14]	'		85,000	[10],[14]
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[10],[14]	'		0	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10],[14]	'		0	[10],[14]
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	922,000	[10],[14]	'		1,078,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	4,000	[10],[14]	'		81,000	[10],[14]
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	481,000	[10],[14]	'		0	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	132,000	[10],[14]	'		0	[10],[14]
Public Service Co Of Oklahoma [Member] \| Risk Management Commodity Contracts [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-54,000	[10],[14]	'		5,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	-53,000	[10],[14]	'		4,000	[10],[14]
Public Service Co Of Oklahoma [Member] \| Energy Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0		'		'
Liabilities:	'		'		'
Risk Management Liabilities	0		'		'
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	0		'		'
Forward Price Range High	0		'		'
Public Service Co Of Oklahoma [Member] \| FTRs [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	481,000		'		'
Liabilities:	'		'		'
Risk Management Liabilities	132,000		'		'
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	-5.05		'		'
Forward Price Range High	9.17		'		'
Public Service Co Of Oklahoma [Member] \| Commodity Hedges [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		84,000	[10]
Public Service Co Of Oklahoma [Member] \| Commodity Hedges [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Public Service Co Of Oklahoma [Member] \| Commodity Hedges [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		84,000	[10]
Public Service Co Of Oklahoma [Member] \| Commodity Hedges [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Public Service Co Of Oklahoma [Member] \| Commodity Hedges [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Southwestern Electric Power Co [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	17,995,000	[1]	'		17,241,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		1,179,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	19,902,000		'		18,420,000
Changes in the Fair Value of Net Trading Derivatives and other investments	'		'		'
Beginning Balance	0		0		0
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	0	[2],[3]	0	[2],[3]	'
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	0	[2]	0	[2]	'
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income	0		0		'
Purchases, Issuances and Settlements	0	[4]	0	[4]	'
Transfers into Level 3	0	[5],[6]	0	[5],[6]	'
Transfers out of Level 3	0	[6],[7]	0	[6],[7]	'
Changes in Fair Value Allocated to Regulated Jurisdictions	442,000	[8]	0	[8]	'
Ending Balance	442,000		0		'
Southwestern Electric Power Co [Member] \| Level 1 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	15,537,000	[1]	'		15,871,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	15,537,000		'		15,871,000
Southwestern Electric Power Co [Member] \| Level 2 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	0	[1]	'		0	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		1,330,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	1,471,000		'		1,330,000
Southwestern Electric Power Co [Member] \| Level 3 [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	0	[1]	'		0	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	609,000		'		0
Southwestern Electric Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Assets:	'		'		'
Cash and Cash Equivalents	2,458,000	[1]	'		1,370,000	[1]
Risk Management Assets	'		'		'
Risk Management Assets	'		'		-151,000
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Total Assets	2,285,000		'		1,219,000
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	1,907,000	[10],[14]	'		1,082,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10],[14]	'		0	[10],[14]
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[10],[14]	'		0	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	0	[10],[14]	'		0	[10],[14]
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	1,471,000	[10],[14]	'		1,233,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	4,000	[10],[14]	'		154,000	[10],[14]
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	609,000	[10],[14]	'		0	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	167,000	[10],[14]	'		0	[10],[14]
Southwestern Electric Power Co [Member] \| Risk Management Commodity Contracts [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	-173,000	[10],[14]	'		-151,000	[10],[14]
Liabilities:	'		'		'
Risk Management Liabilities	-171,000	[10],[14]	'		-154,000	[10],[14]
Southwestern Electric Power Co [Member] \| Energy Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0		'		'
Liabilities:	'		'		'
Risk Management Liabilities	0		'		'
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	0		'		'
Forward Price Range High	0		'		'
Southwestern Electric Power Co [Member] \| FTRs [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	609,000		'		'
Liabilities:	'		'		'
Risk Management Liabilities	167,000		'		'
Level 3 Quantitative Information [Abstract]	'		'		'
Forward Price Range Low	-5.05		'		'
Forward Price Range High	9.17		'		'
Southwestern Electric Power Co [Member] \| Commodity Hedges [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		97,000	[10]
Southwestern Electric Power Co [Member] \| Commodity Hedges [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Southwestern Electric Power Co [Member] \| Commodity Hedges [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		97,000	[10]
Southwestern Electric Power Co [Member] \| Commodity Hedges [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Southwestern Electric Power Co [Member] \| Commodity Hedges [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	'		'		0	[10]
Cash [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	206,000,000	[1]	'		250,000,000	[1]
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	12,000,000	[15]	'		19,000,000	[15]
Cash [Member] \| Level 1 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	187,000,000	[1]	'		231,000,000	[1]
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	3,000,000	[15]	'		8,000,000	[15]
Cash [Member] \| Level 2 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	7,000,000	[1]	'		8,000,000	[1]
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[15]	'		0	[15]
Cash [Member] \| Level 3 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	0	[1]	'		0	[1]
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[15]	'		0	[15]
Cash [Member] \| Fair Value Inputs Other [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	12,000,000	[1]	'		11,000,000	[1]
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	9,000,000	[15]	'		11,000,000	[15]
Cash [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	12,439,000	[16]	'		18,804,000	[16]
Cash [Member] \| Indiana Michigan Power Co [Member] \| Level 1 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	3,576,000	[16]	'		8,082,000	[16]
Cash [Member] \| Indiana Michigan Power Co [Member] \| Level 2 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[16]	'		0	[16]
Cash [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[16]	'		0	[16]
Cash [Member] \| Indiana Michigan Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	8,863,000	[16]	'		10,722,000	[16]
Fixed Income Funds [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	930,000,000		'		901,000,000
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	930,000,000		'		901,000,000
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] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	929,567,000		'		900,295,000
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	929,567,000		'		900,295,000
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Fixed Income Funds [Member] \| Indiana Michigan Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Mutual Funds Fixed Income [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	80,000,000		'		80,000,000
Mutual Funds Fixed Income [Member] \| Level 1 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	80,000,000		'		80,000,000
Mutual Funds Fixed Income [Member] \| Level 2 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	0		'		0
Mutual Funds Fixed Income [Member] \| Level 3 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	0		'		0
Mutual Funds Fixed Income [Member] \| Fair Value Inputs Other [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	0		'		0
Domestic [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	1,020,000,000	[17]	'		1,012,000,000	[17]
Domestic [Member] \| Level 1 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	1,020,000,000	[17]	'		1,012,000,000	[17]
Domestic [Member] \| Level 2 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[17]	'		0	[17]
Domestic [Member] \| Level 3 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[17]	'		0	[17]
Domestic [Member] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[17]	'		0	[17]
Domestic [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	1,020,145,000	[17]	'		1,012,511,000	[17]
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Level 1 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	1,020,145,000	[17]	'		1,012,511,000	[17]
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Level 2 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[17]	'		0	[17]
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[17]	'		0	[17]
Domestic [Member] \| Indiana Michigan Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0	[17]	'		0	[17]
Mutual Funds Equity [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	24,000,000	[17]	'		23,000,000	[17]
Mutual Funds Equity [Member] \| Level 1 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	24,000,000	[17]	'		23,000,000	[17]
Mutual Funds Equity [Member] \| Level 2 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	0	[17]	'		0	[17]
Mutual Funds Equity [Member] \| Level 3 [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	0	[17]	'		0	[17]
Mutual Funds Equity [Member] \| Fair Value Inputs Other [Member]	'		'		'
Assets:	'		'		'
Other Temporary Investments	0	[17]	'		0	[17]
Cash and Cash Equivalents [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	12,000,000		'		19,000,000
Cash and Cash Equivalents [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	12,439,000		'		18,804,000
US Government Agencies Debt Securities [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	606,000,000		'		609,000,000
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	606,000,000		'		609,000,000
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] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	606,228,000		'		608,875,000
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	606,228,000		'		608,875,000
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
US Government Agencies Debt Securities [Member] \| Indiana Michigan Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Corporate Debt [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	43,000,000		'		37,000,000
Corporate Debt [Member] \| Level 1 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Corporate Debt [Member] \| Level 2 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	43,000,000		'		37,000,000
Corporate Debt [Member] \| Level 3 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Corporate Debt [Member] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Corporate Debt [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	42,727,000		'		36,782,000
Corporate Debt [Member] \| Indiana Michigan Power Co [Member] \| Level 1 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Corporate Debt [Member] \| Indiana Michigan Power Co [Member] \| Level 2 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	42,727,000		'		36,782,000
Corporate Debt [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Corporate Debt [Member] \| Indiana Michigan Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
State and Local Jurisdiction [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	281,000,000		'		255,000,000
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	281,000,000		'		255,000,000
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] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
State and Local Jurisdiction [Member] \| Indiana Michigan Power Co [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	280,612,000		'		254,638,000
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	280,612,000		'		254,638,000
State and Local Jurisdiction [Member] \| Indiana Michigan Power Co [Member] \| Level 3 [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
State and Local Jurisdiction [Member] \| Indiana Michigan Power Co [Member] \| Fair Value Inputs Other [Member]	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	'		'		'
Spent Nuclear Fuel and Decommissioning Trusts	0		'		0
Dedesignated Risk Management Contracts [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	4,000,000	[18]	'		6,000,000	[18]
Dedesignated Risk Management Contracts [Member] \| Level 1 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[18]	'		0	[18]
Dedesignated Risk Management Contracts [Member] \| Level 2 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[18]	'		0	[18]
Dedesignated Risk Management Contracts [Member] \| Level 3 [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	0	[18]	'		0	[18]
Dedesignated Risk Management Contracts [Member] \| Fair Value Inputs Other [Member]	'		'		'
Risk Management Assets	'		'		'
Risk Management Assets	$4,000,000	[18]	'		$6,000,000	[18]

[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 condensed statements of income.
[3]	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
[4]	Represents the settlement of risk management commodity contracts for the reporting period.
[5]	Represents existing assets or liabilities that were previously categorized as Level 2.
[6]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[7]	Represents existing assets or liabilities that were previously categorized as Level 3.
[8]	Relates to the net gains (losses) of those contracts that are not reflected on the condensed statements of income. These net gains (losses) are recorded as regulatory liabilities/assets.
[9]	Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
[10]	Amounts in ''Other'' column primarily represent counterparty netting of risk management and hedging contracts and associated cash collateral under the accounting guidance for ''Derivatives and Hedging.''
[11]	The March 31, 2014 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 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $32 million in 2014, $56 million in periods 2015-2017, $8 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $15 million in 2014, $49 million in periods 2015-2017, $16 million in periods 2018-2019 and $23 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.
[12]	The December 31, 2013 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $4 million in 2014, $(11) million in periods 2015-2017 and $(1) million in periods 2018-2019; Level 2 matures $25 million in 2014, $37 million in periods 2015-2017, $7 million in periods 2018-2019 and $5 million in periods 2020-2030; Level 3 matures $27 million in 2014, $60 million in periods 2015-2017, $14 million in periods 2018-2019 and $19 million in periods 2020-2030. Risk management commodity contracts are substantially comprised of power contracts.
[13]	Represents market prices in dollars per MWh.
[14]	Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
[15]	Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[16]	Amounts in bOtherb column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[17]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[18]	Represents contracts that were originally MTM but were subsequently elected as normal under the accounting guidance for ''Derivatives and Hedging.'' At the time of the normal election, the MTM value was frozen and no longer fair valued. This MTM value will be amortized into revenues over the remaining life of the contracts.

Income_Taxes_Details

Income Taxes (Details) (USD $)	3 Months Ended
Income Taxes (Details) (USD $)	Mar. 31, 2014	Mar. 31, 2013
Income Taxes (Textuals) [Abstract]	'	'
Income Tax Benefit	($307,000,000)	($195,000,000)
Interest and Investment Income	1,000,000	3,000,000
Net Income (Loss)	561,000,000	364,000,000
Appalachian Power Co [Member]	'	'
Income Taxes (Textuals) [Abstract]	'	'
Income Tax Benefit	-66,248,000	-47,012,000
Net Income (Loss)	101,851,000	70,548,000
Indiana Michigan Power Co [Member]	'	'
Income Taxes (Textuals) [Abstract]	'	'
Income Tax Benefit	-38,315,000	-21,263,000
Net Income (Loss)	87,089,000	43,457,000
Ohio Power Co [Member]	'	'
Income Taxes (Textuals) [Abstract]	'	'
Income Tax Benefit	-34,052,000	-69,796,000
Net Income (Loss)	60,774,000	129,774,000
Public Service Co Of Oklahoma [Member]	'	'
Income Taxes (Textuals) [Abstract]	'	'
Income Tax Benefit	-4,989,000	-8,634,000
Net Income (Loss)	8,448,000	13,693,000
Southwestern Electric Power Co [Member]	'	'
Income Taxes (Textuals) [Abstract]	'	'
Income Tax Benefit	-12,165,000	-6,796,000
Net Income (Loss)	$22,962,000	$11,548,000

Financing_Activities_Details

Financing Activities (Details) (USD $)

3 Months Ended

1 Months Ended

3 Months Ended

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

Apr. 25, 2014

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

Mar. 31, 2013

Dec. 31, 2013

Mar. 31, 2014

AEP Subsidiaries [Member]

AEP Generating Co [Member]

AEP Texas Central Co [Member]

Appalachian Power Co [Member]

Indiana Michigan Power Co [Member]

Ohio Power Co [Member]

Public Service Co Of Oklahoma [Member]

Southwestern Electric Power Co [Member]

Transource Missouri [Member]

Notes Payable One [Member]

Senior Unsecured Notes One [Member]

Securitization Bonds One [Member]

Securitization Bonds Two [Member]

Land Note [Member]

Notes Payable One [Member]

Notes Payable Two [Member]

Notes Payable Three [Member]

Notes Payable Four [Member]

Long-term Debt [Member]

Long Term Debt Two [Member]

Senior Unsecured Notes One [Member]

Long-term Debt [Member]

Long Term Debt Two [Member]

Notes Payable Two [Member]

Long-term Debt [Member]

Subsequent Event [Member]

Long-term Debt

Senior Unsecured Notes

$11,571,000,000

$11,799,000,000

Pollution Control Bonds

1,932,000,000

Notes Payable

342,000,000

369,000,000

Securitization Bonds

2,574,000,000

2,686,000,000

Spent Nuclear Fuel Obligation

265,000,000

[1]

265,000,000

[1]

Other Long-term Debt

1,434,000,000

1,360,000,000

Fair Value of Interest Rate Hedges

-7,000,000

-9,000,000

Unamortized Discount, Net

-24,000,000

-25,000,000

Total Long-term Debt Outstanding

18,087,000,000

18,377,000,000

4,194,516,000

4,194,357,000

2,012,844,000

2,039,016,000

2,510,285,000

2,735,175,000

1,049,793,000

999,810,000

2,041,796,000

2,043,332,000

Long-term Debt Due Within One Year

1,612,000,000

1,549,000,000

449,000,000

416,000,000

553,399,000

342,360,000

287,598,000

294,845,000

235,785,000

438,595,000

34,118,000

34,115,000

56,750,000

3,250,000

Long-term Debt

16,475,000,000

16,828,000,000

2,388,000,000

2,532,000,000

3,555,117,000

3,765,997,000

1,725,246,000

1,744,171,000

2,274,500,000

2,296,580,000

1,015,675,000

965,695,000

1,985,046,000

2,040,082,000

Long-term Debt and Other Securities Issued, Retired and Principal Payments Made

Issuances

77,000,000

[2]

50,000,000

27,000,000

Retirements and Principal Payments

370,000,000

858,000,000

1,000,000

4,000,000

72,000,000

40,000,000

8,000

7,000

8,000

26,337,000

24,864,000

9,866,000

13,000,000

5,324,000

5,214,000

3,611,000

2,063,000

259,000

225,029,000

500,000,000

225,000,000

29,000

102,000

99,000

102,000

1,625,000

Interest Rate (Percentage)

6.33%

5.09%

6.25%

13.72%

2.12%

6.00%

4.85%

1.15%

3.00%

4.58%

Interest Rate (Variable)

'Variable

Due Date

'2017

'2037

'2015

'2016

'2026

'2017

'2016

'2015

'2025

'2014

'2028

'2016

'2027

'2032

'2018

Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits

Maximum Borrowings from Utility Money Pool

55,640,000

121,100,000

130,258,000

Maximum Loans to Utility Money Pool

249,630,000

158,857,000

405,350,000

Average Borrowings from Utility Money Pool

25,930,000

58,500,000

61,132,000

Average Loans to Utility Money Pool

164,681,000

92,303,000

135,747,000

Net Loans (Borrowings) to/from Utility Money Pool

245,516,000

59,162,000

-27,108,000

-70,119,000

-117,342,000

Authorized Short-term Borrowing Limit

600,000,000

500,000,000

600,000,000

300,000,000

350,000,000

Maximum and Minimum Interest Rates

Maximum Interest Rate

0.33%

0.43%

0.33%

0.43%

0.33%

0.43%

0.33%

0.43%

0.33%

0.43%

Minimum Interest Rate

0.28%

0.35%

0.28%

0.35%

0.28%

0.35%

0.28%

0.35%

0.28%

0.35%

Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool

Average Interest Rate for Funds Borrowed

0.00%

0.38%

0.00%

0.36%

0.31%

0.36%

0.31%

0.36%

0.31%

0.00%

Average Interest Rate for Funds Loaned

0.31%

0.37%

0.31%

0.37%

0.29%

0.37%

0.00%

0.38%

0.00%

0.38%

Short-term Debt:

Securitized Debt for Receivables

700,000,000

[3]

700,000,000

[3]

Commercial Paper

632,000,000

57,000,000

Total Short-term Debt

1,332,000,000

757,000,000

Securitized Debt for Receivables

0.24%

[4]

0.23%

[4]

Commercial Paper

0.31%

[4]

0.29%

[4]

Comparative Accounts Receivable Information

Effective Interest Rates on Securitization of Accounts Receivable

0.24%

0.23%

Net Uncollectible Accounts Receivable Written Off

8,000,000

7,000,000

Customer Accounts Receivable Managed Portfolio

Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts

997,000,000

929,000,000

Total Principal Outstanding

700,000,000

Delinquent Securitized Accounts Receivable

55,000,000

45,000,000

Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable

17,000,000

16,000,000

Unbilled Receivables Related to Securitization, Sale of Accounts Receivable

278,000,000

331,000,000

Accounts Receivable and Accrued Unbilled Revenues

175,738,000

156,599,000

154,510,000

139,257,000

350,735,000

324,287,000

111,522,000

115,260,000

145,648,000

149,337,000

Fees Paid to AEP Credit for Customer Accounts Receivable Sold

2,423,000

1,556,000

2,040,000

1,452,000

7,498,000

4,669,000

1,323,000

1,414,000

1,566,000

1,380,000

Proceeds from Sale of Receivables

Proceeds from Sale of Receivables to AEP Credit

437,196,000

398,193,000

407,150,000

351,830,000

686,627,000

696,958,000

290,217,000

240,275,000

390,588,000

331,936,000

Financing Activities (Textuals) [Abstract]

Reacquired Pollution Controls Bonds Held by Trustees

500,000,000

40,000,000

460,000,000

Maximum Percentage Debt to Capitalization

67.50%

Commitment from Bank Conduits that Expire in One Year

385,000,000

Commitment from Bank Conduits that Expire in Two Years

315,000,000

Total Commitment from Bank Conduits to Finance Receivables

700,000,000

Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition

$309,000,000

[1]

Pursuant to the Nuclear Waste Policy Act of 1982, I&M, a nuclear licensee, has an obligation to the United States Department of Energy for spent nuclear fuel disposal. The obligation includes a one-time fee for nuclear fuel consumed prior to April 7, 1983. Trust fund assets related to this obligation were $309 million and $309 million as of March 31, 2014 and December 31, 2013, respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.

[2]

Amount indicated on the statement of cash flows is net of issuance costs and premium or discount and will not tie to the total issuances.

[3]

Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance.

[4]

Weighted average rate.

Variable_Interest_Entities_Det

Variable Interest Entities (Details) (USD $)	3 Months Ended
Variable Interest Entities (Details) (USD $)	Mar. 31, 2014		Mar. 31, 2013	Dec. 31, 2013
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Minimum Percentage of Equity AEP Provides	5.00%		'	'
Securitization Bonds	$2,574,000,000		'	$2,686,000,000
Securitized Transition Assets	2,308,000,000		'	2,373,000,000
AEP Credit, Inc. [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Percentage of Short Term Borrowing Needs in Excess of Third Party Financings	20.00%		'	'
AEP Texas Central Transition Funding Co [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Securitization Bonds	2,000,000,000		'	2,000,000,000
Securitized Transition Assets	1,800,000,000		'	1,900,000,000
Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Insurance Premium Expense to Protected Cell	16,000,000		15,000,000	'
PATH West Virginia Transmission Co, LLC [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	25,000,000		'	25,000,000
Maximum Exposure	25,000,000		'	25,000,000
Transource Energy, LLC [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Equity and Voting Ownership Percentage	86.50%		'	'
Capital Contribution From Parent [Member] \| PATH West Virginia Transmission Co, LLC [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	19,000,000		'	19,000,000
Maximum Exposure	19,000,000		'	19,000,000
Retained Earnings [Member] \| PATH West Virginia Transmission Co, LLC [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	6,000,000		'	6,000,000
Maximum Exposure	6,000,000		'	6,000,000
Current Assets [Member] \| AEP Credit, Inc. [Member]	'		'	'
ASSETS	'		'	'
Assets	1,004,000,000		'	935,000,000
Current Assets [Member] \| AEP Texas Central Transition Funding Co [Member]	'		'	'
ASSETS	'		'	'
Assets	166,000,000		'	232,000,000
Current Assets [Member] \| Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
ASSETS	'		'	'
Assets	152,000,000		'	143,000,000
Current Assets [Member] \| Transource Energy, LLC [Member]	'		'	'
ASSETS	'		'	'
Assets	4,000,000		'	'
Net Property Plant And Equipment [Member] \| AEP Credit, Inc. [Member]	'		'	'
ASSETS	'		'	'
Assets	0		'	0
Net Property Plant And Equipment [Member] \| AEP Texas Central Transition Funding Co [Member]	'		'	'
ASSETS	'		'	'
Assets	0		'	0
Net Property Plant And Equipment [Member] \| Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
ASSETS	'		'	'
Assets	0		'	0
Net Property Plant And Equipment [Member] \| Transource Energy, LLC [Member]	'		'	'
ASSETS	'		'	'
Assets	57,000,000		'	'
Other Non Current Assets [Member] \| AEP Credit, Inc. [Member]	'		'	'
ASSETS	'		'	'
Assets	0		'	1,000,000
Other Non Current Assets [Member] \| AEP Texas Central Transition Funding Co [Member]	'		'	'
ASSETS	'		'	'
Assets	1,861,000,000	[1]	'	1,918,000,000	[2]
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Intercompany Item Eliminated in Consolidation	81,000,000		'	82,000,000
Other Non Current Assets [Member] \| Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
ASSETS	'		'	'
Assets	3,000,000		'	3,000,000
Other Non Current Assets [Member] \| Transource Energy, LLC [Member]	'		'	'
ASSETS	'		'	'
Assets	5,000,000		'	'
Total Assets [Member] \| AEP Credit, Inc. [Member]	'		'	'
ASSETS	'		'	'
Assets	1,004,000,000		'	936,000,000
Total Assets [Member] \| AEP Texas Central Transition Funding Co [Member]	'		'	'
ASSETS	'		'	'
Assets	2,027,000,000		'	2,150,000,000
Total Assets [Member] \| Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
ASSETS	'		'	'
Assets	155,000,000		'	146,000,000
Total Assets [Member] \| Transource Energy, LLC [Member]	'		'	'
ASSETS	'		'	'
Assets	66,000,000		'	'
Current Liabilities [Member] \| AEP Credit, Inc. [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	894,000,000		'	827,000,000
Current Liabilities [Member] \| AEP Texas Central Transition Funding Co [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	304,000,000		'	312,000,000
Current Liabilities [Member] \| Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	48,000,000		'	39,000,000
Current Liabilities [Member] \| Transource Energy, LLC [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	18,000,000		'	'
Noncurrent Liabilities [Member] \| AEP Credit, Inc. [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	1,000,000		'	1,000,000
Noncurrent Liabilities [Member] \| AEP Texas Central Transition Funding Co [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	1,705,000,000		'	1,820,000,000
Noncurrent Liabilities [Member] \| Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	67,000,000		'	66,000,000
Noncurrent Liabilities [Member] \| Transource Energy, LLC [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	28,000,000		'	'
Equity [Member] \| AEP Credit, Inc. [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	109,000,000		'	108,000,000
Equity [Member] \| AEP Texas Central Transition Funding Co [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	18,000,000		'	18,000,000
Equity [Member] \| Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	40,000,000		'	41,000,000
Equity [Member] \| Transource Energy, LLC [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	20,000,000		'	'
Total Liabilities And Equity [Member] \| AEP Credit, Inc. [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	1,004,000,000		'	936,000,000
Total Liabilities And Equity [Member] \| AEP Texas Central Transition Funding Co [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	2,027,000,000		'	2,150,000,000
Total Liabilities And Equity [Member] \| Protected Cell Of Energy Insurance Services, Inc. [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	155,000,000		'	146,000,000
Total Liabilities And Equity [Member] \| Transource Energy, LLC [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	66,000,000		'	'
Appalachian Power Co [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Securitized Transition Assets	364,984,000		'	369,355,000
Appalachian Power Co [Member] \| Billings from American Electric Power Service Corporation [Member]	'		'	'
Billings from Affiliates	'		'	'
Billings from VIE	50,136,000		39,040,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	50,136,000		39,040,000	'
Appalachian Power Co [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	19,304,000		'	20,191,000
Maximum Exposure	19,304,000		'	20,191,000
Appalachian Power Co [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Securitization Bonds	380,000,000		'	380,000,000
Securitized Transition Assets	365,000,000		'	369,000,000
Appalachian Power Co [Member] \| Current Assets [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
ASSETS	'		'	'
Assets	15,981,000		'	5,891,000
Appalachian Power Co [Member] \| Net Property Plant And Equipment [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
ASSETS	'		'	'
Assets	0		'	0
Appalachian Power Co [Member] \| Other Non Current Assets [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
ASSETS	'		'	'
Assets	373,521,000	[3]	'	378,029,000	[3]
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Intercompany Item Eliminated in Consolidation	4,000,000		'	4,000,000
Appalachian Power Co [Member] \| Total Assets [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
ASSETS	'		'	'
Assets	389,502,000		'	383,920,000
Appalachian Power Co [Member] \| Current Liabilities [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	27,682,000		'	14,000,000
Appalachian Power Co [Member] \| Noncurrent Liabilities [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	359,919,000		'	368,018,000
Appalachian Power Co [Member] \| Equity [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	1,901,000		'	1,902,000
Appalachian Power Co [Member] \| Total Liabilities And Equity [Member] \| Appalachian Consumer Rate Relief Funding [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	389,502,000		'	383,920,000
Indiana Michigan Power Co [Member] \| DCC Fuel [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Payments Made by I&M to DCC Fuel	25,000,000		26,000,000	'
Indiana Michigan Power Co [Member] \| Billings from AEP Generating Co [Member]	'		'	'
Billings from Affiliates	'		'	'
Billings from VIE	70,422,000		58,535,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	70,422,000		58,535,000	'
Indiana Michigan Power Co [Member] \| Billings from American Electric Power Service Corporation [Member]	'		'	'
Billings from Affiliates	'		'	'
Billings from VIE	31,969,000		27,498,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	31,969,000		27,498,000	'
Indiana Michigan Power Co [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	12,040,000		'	12,864,000
Maximum Exposure	12,040,000		'	12,864,000
Indiana Michigan Power Co [Member] \| Carrying Amount in AEGCo's Accounts Payable [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	24,364,000		'	23,916,000
Maximum Exposure	24,364,000		'	23,916,000
Indiana Michigan Power Co [Member] \| Current Assets [Member] \| DCC Fuel [Member]	'		'	'
ASSETS	'		'	'
Assets	109,374,000		'	117,762,000
Indiana Michigan Power Co [Member] \| Net Property Plant And Equipment [Member] \| DCC Fuel [Member]	'		'	'
ASSETS	'		'	'
Assets	129,013,000		'	156,820,000
Indiana Michigan Power Co [Member] \| Other Non Current Assets [Member] \| DCC Fuel [Member]	'		'	'
ASSETS	'		'	'
Assets	44,853,000		'	60,450,000
Indiana Michigan Power Co [Member] \| Total Assets [Member] \| DCC Fuel [Member]	'		'	'
ASSETS	'		'	'
Assets	283,240,000		'	335,032,000
Indiana Michigan Power Co [Member] \| Current Liabilities [Member] \| DCC Fuel [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	100,141,000		'	107,815,000
Indiana Michigan Power Co [Member] \| Noncurrent Liabilities [Member] \| DCC Fuel [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	183,099,000		'	227,217,000
Indiana Michigan Power Co [Member] \| Total Liabilities And Equity [Member] \| DCC Fuel [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	283,240,000		'	335,032,000
Ohio Power Co [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Securitized Transition Assets	126,597,000		'	131,582,000
Ohio Power Co [Member] \| Ohio Phase-In-Recovery Funding [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Securitization Bonds	267,000,000		'	267,000,000
Securitized Transition Assets	127,000,000		'	132,000,000
Ohio Power Co [Member] \| Billings from AEP Generating Co [Member]	'		'	'
Billings from Affiliates	'		'	'
Billings from VIE	0		38,711,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	0		38,711,000	'
Ohio Power Co [Member] \| Billings from American Electric Power Service Corporation [Member]	'		'	'
Billings from Affiliates	'		'	'
Billings from VIE	39,049,000		54,069,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	39,049,000		54,069,000	'
Ohio Power Co [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	14,046,000		'	31,425,000
Maximum Exposure	14,046,000		'	31,425,000
Ohio Power Co [Member] \| Carrying Amount in AEGCo's Accounts Payable [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	0		'	12,810,000
Maximum Exposure	0		'	12,810,000
Ohio Power Co [Member] \| Current Assets [Member] \| Ohio Phase-In-Recovery Funding [Member]	'		'	'
ASSETS	'		'	'
Assets	35,958,000		'	23,198,000
Ohio Power Co [Member] \| Other Non Current Assets [Member] \| Ohio Phase-In-Recovery Funding [Member]	'		'	'
ASSETS	'		'	'
Assets	241,814,000	[4]	'	251,409,000	[4]
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Intercompany Item Eliminated in Consolidation	112,000,000		'	116,000,000
Ohio Power Co [Member] \| Total Assets [Member] \| Ohio Phase-In-Recovery Funding [Member]	'		'	'
ASSETS	'		'	'
Assets	277,772,000		'	274,607,000
Ohio Power Co [Member] \| Current Liabilities [Member] \| Ohio Phase-In-Recovery Funding [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	59,590,000		'	36,470,000
Ohio Power Co [Member] \| Noncurrent Liabilities [Member] \| Ohio Phase-In-Recovery Funding [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	216,845,000		'	236,800,000
Ohio Power Co [Member] \| Equity [Member] \| Ohio Phase-In-Recovery Funding [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	1,337,000		'	1,337,000
Ohio Power Co [Member] \| Total Liabilities And Equity [Member] \| Ohio Phase-In-Recovery Funding [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	277,772,000		'	274,607,000
Public Service Co Of Oklahoma [Member] \| Billings from American Electric Power Service Corporation [Member]	'		'	'
Billings from Affiliates	'		'	'
Billings from VIE	24,439,000		18,161,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	24,439,000		18,161,000	'
Public Service Co Of Oklahoma [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	9,330,000		'	10,596,000
Maximum Exposure	9,330,000		'	10,596,000
Southwestern Electric Power Co [Member] \| Sabine Mining Co [Member]	'		'	'
Billings from Affiliates	'		'	'
Billings from VIE	39,000,000		44,000,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	39,000,000		44,000,000	'
Southwestern Electric Power Co [Member] \| Dolet Hills Lignite Co, LLC [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	9,553,000		'	9,243,000
Maximum Exposure	94,743,000		'	70,591,000
Billings from Affiliates	'		'	'
Billings from VIE	2,000,000		18,000,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	2,000,000		18,000,000	'
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] \| Billings from American Electric Power Service Corporation [Member]	'		'	'
Billings from Affiliates	'		'	'
Billings from VIE	33,023,000		27,480,000	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Billings from VIE	33,023,000		27,480,000	'
Southwestern Electric Power Co [Member] \| Carrying Amount in AEPSC's Accounts Payable [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	12,833,000		'	13,520,000
Maximum Exposure	12,833,000		'	13,520,000
Southwestern Electric Power Co [Member] \| Capital Contribution From Parent [Member] \| Dolet Hills Lignite Co, LLC [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	7,643,000		'	7,643,000
Maximum Exposure	7,643,000		'	7,643,000
Southwestern Electric Power Co [Member] \| Retained Earnings [Member] \| Dolet Hills Lignite Co, LLC [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	1,910,000		'	1,600,000
Maximum Exposure	1,910,000		'	1,600,000
Southwestern Electric Power Co [Member] \| SWEPCo's Guarantee Of Debt [Member] \| Dolet Hills Lignite Co, LLC [Member]	'		'	'
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]	'		'	'
As Reported on the Consolidated Balance Sheet	0		'	0
Maximum Exposure	85,190,000		'	61,348,000
Southwestern Electric Power Co [Member] \| Current Assets [Member] \| Sabine Mining Co [Member]	'		'	'
ASSETS	'		'	'
Assets	61,675,000		'	66,478,000
Southwestern Electric Power Co [Member] \| Net Property Plant And Equipment [Member] \| Sabine Mining Co [Member]	'		'	'
ASSETS	'		'	'
Assets	153,928,000		'	157,274,000
Southwestern Electric Power Co [Member] \| Other Non Current Assets [Member] \| Sabine Mining Co [Member]	'		'	'
ASSETS	'		'	'
Assets	50,140,000		'	51,211,000
Southwestern Electric Power Co [Member] \| Total Assets [Member] \| Sabine Mining Co [Member]	'		'	'
ASSETS	'		'	'
Assets	265,743,000		'	274,963,000
Southwestern Electric Power Co [Member] \| Current Liabilities [Member] \| Sabine Mining Co [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	29,257,000		'	32,812,000
Southwestern Electric Power Co [Member] \| Noncurrent Liabilities [Member] \| Sabine Mining Co [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	236,142,000		'	241,673,000
Southwestern Electric Power Co [Member] \| Equity [Member] \| Sabine Mining Co [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	344,000		'	478,000
Southwestern Electric Power Co [Member] \| Total Liabilities And Equity [Member] \| Sabine Mining Co [Member]	'		'	'
LIABILITIES AND EQUITY	'		'	'
Liabilities and Equity	$265,743,000		'	$274,963,000
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%		'	'
Cleco Power, LLC [Member] \| Dolet Hills Lignite Co, LLC [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Percentage of VIE Sales of Lignite Produced	50.00%		'	'
Great Plains Energy Inc [Member] \| Transource Energy, LLC [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Equity and Voting Ownership Percentage	13.50%		'	'
First Energy Corp [Member] \| Allegheny Series [Member]	'		'	'
Variable Interest Entities (Textuals) [Abstract]	'		'	'
Percentage of Ownership in Subsidiary	100.00%		'	'

[1]	Includes an intercompany item eliminated in consolidation of $81 million.
[2]	B B B B B B B B Includes an intercompany item eliminated in consolidation of $82 million.
[3]	Includes an intercompany item eliminated in consolidation as of March 31, 2014 of and December 31, 2013 of $4 million and $4 million, respectively.
[4]	Includes an intercompany item eliminated in consolidation as of March 31, 2014 and December 31, 2013 of $112 million and $116 million, respectively.