Indiana Michigan Power 10-Q 23 Jul 15 2015 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 23, 2015
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	4,904
Document Type	10-Q
Document Period End Date	Jun. 30, 2015
Amendment Flag	false
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		490,559,618
Appalachian Power Co [Member]
Entity Registrant Name	APPALACHIAN POWER CO
Entity Central Index Key	6,879
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		13,499,500
Indiana Michigan Power Co [Member]
Entity Registrant Name	INDIANA MICHIGAN POWER CO
Entity Central Index Key	50,172
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		1,400,000
Ohio Power Co [Member]
Entity Registrant Name	OHIO POWER CO
Entity Central Index Key	73,986
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		27,952,473
Public Service Co Of Oklahoma [Member]
Entity Registrant Name	PUBLIC SERVICE CO OF OKLAHOMA
Entity Central Index Key	81,027
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		9,013,000
Southwestern Electric Power Co [Member]
Entity Registrant Name	SOUTHWESTERN ELECTRIC POWER CO
Entity Central Index Key	92,487
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		7,536,640

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Revenues
Vertically Integrated Utilities	$ 2,159,000	$ 2,236,000	$ 4,646,000	$ 4,785,000
Transmission and Distribution Utilities	1,008,000	1,064,000	2,214,000	2,225,000
Generation & Marketing	628,000	573,000	1,487,000	1,394,000
Other Revenues	147,000	171,000	303,000	288,000
TOTAL REVENUES	3,942,000	4,044,000	8,650,000	8,692,000
Expenses
Fuel and Other Consumables Used for Electric Generation	756,000	1,043,000	1,827,000	2,211,000
Purchased Electricity for Resale	601,000	473,000	1,319,000	1,111,000
Other Operation	695,000	760,000	1,441,000	1,540,000
Maintenance	333,000	340,000	627,000	632,000
Depreciation and Amortization	506,000	443,000	1,011,000	934,000
Taxes Other Than Income Taxes	242,000	218,000	492,000	456,000
TOTAL EXPENSES	3,133,000	3,277,000	6,717,000	6,884,000
OPERATING INCOME (LOSS)	809,000	767,000	1,933,000	1,808,000
Other Income (Expense):
Interest and Investment Income	3,000	3,000	4,000	4,000
Carrying Costs Income	9,000	9,000	17,000	15,000
Allowance for Equity Funds Used During Construction	34,000	25,000	64,000	47,000
Interest Expense	(224,000)	(221,000)	(447,000)	(441,000)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	631,000	583,000	1,571,000	1,433,000
Income Tax Expense (Credit)	225,000	215,000	558,000	522,000
Equity Earnings (Loss) of Unconsolidated Subsidiaries	25,000	23,000	49,000	41,000
NET INCOME (LOSS)	431,000	391,000	1,062,000	952,000
Net Income Attributable to Noncontrolling Interests	1,000	1,000	3,000	2,000
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 430,000	$ 390,000	$ 1,059,000	$ 950,000
Earnings Per Share
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	490,207,482	488,291,576	489,904,417	488,080,505
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 0.88	$ 0.80	$ 2.16	$ 1.95
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	490,484,450	488,538,227	490,212,271	488,405,869
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$ 0.88	$ 0.80	$ 2.16	$ 1.95
CASH DIVIDENDS DECLARED PER SHARE	$ 0.53	$ 0.5	$ 1.06	$ 1
Appalachian Power Co [Member]
Revenues
Vertically Integrated Utilities	$ 645,452	$ 664,051	$ 1,499,631	$ 1,530,508
Sales to AEP Affiliates	33,836	28,070	76,351	72,984
Other Revenues	2,692	2,547	5,013	4,567
TOTAL REVENUES	681,980	694,668	1,580,995	1,608,059
Expenses
Fuel and Other Consumables Used for Electric Generation	183,485	202,903	406,732	433,640
Purchased Electricity for Resale	65,715	86,033	178,384	255,024
Purchased Electricity from AEP Affiliates	0	0	0	4,662
Other Operation	103,720	99,896	209,790	193,434
Maintenance	57,037	69,484	109,334	129,574
Depreciation and Amortization	96,297	95,650	196,440	200,236
Taxes Other Than Income Taxes	30,040	30,025	61,087	60,802
TOTAL EXPENSES	536,294	583,991	1,161,767	1,277,372
OPERATING INCOME (LOSS)	145,686	110,677	419,228	330,687
Other Income (Expense):
Interest Income	449	389	838	790
Carrying Costs Income	417	263	710	(1,612)
Allowance for Equity Funds Used During Construction	3,897	1,625	6,905	2,860
Interest Expense	(48,684)	(53,130)	(98,975)	(104,802)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	101,765	59,824	328,706	227,923
Income Tax Expense (Credit)	42,713	23,577	127,861	89,825
NET INCOME (LOSS)	59,052	36,247	200,845	138,098
Indiana Michigan Power Co [Member]
Revenues
Vertically Integrated Utilities	515,027	506,997	1,081,277	1,121,840
Sales to AEP Affiliates	6,504	1,068	6,957	3,352
Other Revenues - Affiliated	21,931	25,262	40,511	49,989
Other Revenues	812	549	1,840	549
TOTAL REVENUES	544,274	533,876	1,130,585	1,175,730
Expenses
Fuel and Other Consumables Used for Electric Generation	74,041	113,700	173,925	270,343
Purchased Electricity for Resale	50,260	27,086	106,167	32,448
Purchased Electricity from AEP Affiliates	59,993	65,190	114,958	137,246
Other Operation	137,306	146,272	266,266	287,622
Maintenance	59,829	54,246	107,180	102,811
Depreciation and Amortization	49,540	49,446	100,947	99,477
Taxes Other Than Income Taxes	21,977	20,803	45,384	42,626
TOTAL EXPENSES	452,946	476,743	914,827	972,573
OPERATING INCOME (LOSS)	91,328	57,133	215,758	203,157
Other Income (Expense):
Interest Income	3,578	1,729	5,326	2,778
Allowance for Equity Funds Used During Construction	2,907	4,804	6,950	8,768
Interest Expense	(22,968)	(23,705)	(45,745)	(49,338)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	74,845	39,961	182,289	165,365
Income Tax Expense (Credit)	24,264	12,627	59,034	50,942
NET INCOME (LOSS)	50,581	27,334	123,255	114,423
Ohio Power Co [Member]
Revenues
Transmission and Distribution Utilities	670,250	739,962	1,544,467	1,586,868
Sales to AEP Affiliates	33,158	44,443	75,264	76,421
Other Revenues	2,346	1,756	4,463	3,064
TOTAL REVENUES	705,754	786,161	1,624,194	1,666,353
Expenses
Purchased Electricity for Resale	116,434	64,059	258,514	143,189
Purchased Electricity from AEP Affiliates	146,207	267,631	416,811	581,755
Amortization of Generation Deferrals	35,301	24,977	66,755	56,163
Other Operation	129,829	131,485	276,673	282,911
Maintenance	34,214	48,590	81,787	83,241
Depreciation and Amortization	55,640	51,485	114,852	110,184
Taxes Other Than Income Taxes	91,639	83,913	189,426	179,170
TOTAL EXPENSES	609,264	672,140	1,404,818	1,436,613
OPERATING INCOME (LOSS)	96,490	114,021	219,376	229,740
Other Income (Expense):
Interest Income	1,250	2,899	3,163	6,173
Carrying Costs Income	5,153	6,874	11,613	13,988
Allowance for Equity Funds Used During Construction	2,343	1,342	4,787	3,068
Interest Expense	(31,271)	(32,759)	(63,720)	(65,766)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	73,965	92,377	175,219	187,203
Income Tax Expense (Credit)	26,213	35,842	62,100	69,894
NET INCOME (LOSS)	47,752	56,535	113,119	117,309
Public Service Co Of Oklahoma [Member]
Revenues
Vertically Integrated Utilities	317,611	316,524	622,284	613,234
Sales to AEP Affiliates	1,164	854	2,443	5,451
Other Revenues	729	1,437	1,549	1,515
TOTAL REVENUES	319,504	318,815	626,276	620,200
Expenses
Fuel and Other Consumables Used for Electric Generation	52,981	41,612	138,580	107,549
Purchased Electricity for Resale	85,036	104,604	150,559	184,295
Purchased Electricity from AEP Affiliates	0	0	0	11,024
Other Operation	61,028	62,785	121,793	121,496
Maintenance	25,943	29,678	47,083	54,423
Depreciation and Amortization	29,782	24,607	59,316	48,589
Taxes Other Than Income Taxes	9,238	6,651	18,516	18,620
TOTAL EXPENSES	264,008	269,937	535,847	545,996
OPERATING INCOME (LOSS)	55,496	48,878	90,429	74,204
Other Income (Expense):
Interest Income	92	4	128	1
Allowance for Equity Funds Used During Construction	2,283	590	3,610	2,021
Interest Expense	(14,852)	(13,779)	(29,422)	(27,096)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	43,019	35,693	64,745	49,130
Income Tax Expense (Credit)	15,921	13,244	23,962	18,233
NET INCOME (LOSS)	27,098	22,449	40,783	30,897
Southwestern Electric Power Co [Member]
Revenues
Vertically Integrated Utilities	433,187	444,652	861,722	871,279
Sales to AEP Affiliates	4,486	3,947	7,156	17,545
Other Revenues	364	684	868	1,049
TOTAL REVENUES	438,037	449,283	869,746	889,873
Expenses
Fuel and Other Consumables Used for Electric Generation	125,365	161,116	283,097	306,703
Purchased Electricity for Resale	27,188	40,255	47,202	101,420
Purchased Electricity from AEP Affiliates	0	0	0	3,766
Other Operation	67,899	69,304	133,444	137,841
Maintenance	38,237	33,668	65,651	64,079
Depreciation and Amortization	47,964	45,864	94,918	91,525
Taxes Other Than Income Taxes	21,316	20,289	43,048	41,026
TOTAL EXPENSES	327,969	370,496	667,360	746,360
OPERATING INCOME (LOSS)	110,068	78,787	202,386	143,513
Other Income (Expense):
Interest Income	1,184	206	1,164	92
Allowance for Equity Funds Used During Construction	5,882	2,197	11,111	4,278
Interest Expense	(31,945)	(31,738)	(62,160)	(63,614)
INCOME BEFORE INCOME TAX EXPENSE (CREDIT) AND EQUITY EARNINGS (LOSS)	85,189	49,452	152,501	84,269
Income Tax Expense (Credit)	26,887	17,045	48,059	29,210
Equity Earnings (Loss) of Unconsolidated Subsidiaries	1,124	416	1,721	726
NET INCOME (LOSS)	59,426	32,823	106,163	55,785
Net Income Attributable to Noncontrolling Interests	956	1,126	1,989	2,228
EARNINGS ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 58,470	$ 31,697	$ 104,174	$ 53,557

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net Income (Loss)	$ 431,000	$ 391,000	$ 1,062,000	$ 952,000
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	1,000	3,000	(5,000)	8,000
Securities Available for Sale, Net of Tax	(1,000)	1,000	0	1,000
Amortization of Pension and OPEB Deferred Costs, Net of Tax	1,000	1,000	1,000	2,000
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	1,000	5,000	(4,000)	11,000
TOTAL COMPREHENSIVE INCOME (LOSS)	432,000	396,000	1,058,000	963,000
Total Comprehensive Income Attributable to Noncontrolling Interest	1,000	1,000	3,000	2,000
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	431,000	395,000	1,055,000	961,000
Appalachian Power Co [Member]
Net Income (Loss)	59,052	36,247	200,845	138,098
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	2	166	131	412
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(458)	(333)	(916)	(666)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(456)	(167)	(785)	(254)
TOTAL COMPREHENSIVE INCOME (LOSS)	58,596	36,080	200,060	137,844
Indiana Michigan Power Co [Member]
Net Income (Loss)	50,581	27,334	123,255	114,423
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	268	350	535	775
Amortization of Pension and OPEB Deferred Costs, Net of Tax	10	43	22	86
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	278	393	557	861
TOTAL COMPREHENSIVE INCOME (LOSS)	50,859	27,727	123,812	115,284
Ohio Power Co [Member]
Net Income (Loss)	47,752	56,535	113,119	117,309
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(343)	(343)	(686)	(791)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(343)	(343)	(686)	(791)
TOTAL COMPREHENSIVE INCOME (LOSS)	47,409	56,192	112,433	116,518
Public Service Co Of Oklahoma [Member]
Net Income (Loss)	27,098	22,449	40,783	30,897
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	(190)	(190)	(380)	(436)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	(190)	(190)	(380)	(436)
TOTAL COMPREHENSIVE INCOME (LOSS)	26,908	22,259	40,403	30,461
Southwestern Electric Power Co [Member]
Net Income (Loss)	59,426	32,823	106,163	55,785
OTHER COMPREHENSIVE INCOME
Cash Flow Hedges, Net of Tax	567	567	1,134	1,069
Amortization of Pension and OPEB Deferred Costs, Net of Tax	(239)	(235)	(479)	(469)
TOTAL OTHER COMPREHENSIVE INCOME (LOSS)	328	332	655	600
TOTAL COMPREHENSIVE INCOME (LOSS)	59,754	33,155	106,818	56,385
Total Comprehensive Income Attributable to Noncontrolling Interest	956	1,126	1,989	2,228
TOTAL COMPREHENSIVE INCOME (LOSS) ATTRIBUTABLE TO COMMON SHAREHOLDERS	$ 58,798	$ 32,029	$ 104,829	$ 54,157

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Cash Flow Hedges, Tax	$ 0	$ 1,000	$ (3,000)	$ 4,000
Securities Available for Sale, Tax	0	0	0	0
Amortization of Pension and OPEB Deferred Costs, Tax	0	1,000	0	1,000
Appalachian Power Co [Member]
Cash Flow Hedges, Tax	1	90	71	222
Amortization of Pension and OPEB Deferred Costs, Tax	(247)	(180)	(493)	(359)
Indiana Michigan Power Co [Member]
Cash Flow Hedges, Tax	144	189	288	418
Amortization of Pension and OPEB Deferred Costs, Tax	6	23	12	46
Ohio Power Co [Member]
Cash Flow Hedges, Tax	(185)	(185)	(370)	(426)
Public Service Co Of Oklahoma [Member]
Cash Flow Hedges, Tax	(103)	(103)	(205)	(235)
Southwestern Electric Power Co [Member]
Cash Flow Hedges, Tax	306	306	611	576
Amortization of Pension and OPEB Deferred Costs, Tax	$ (129)	$ (127)	$ (258)	$ (253)

Condensed Consolidated Statemen

Condensed Consolidated Statements of Changes in Equity - USD ($) $ in Thousands	Total	Appalachian Power Co [Member]	Indiana Michigan Power Co [Member]	Ohio Power Co [Member]	Public Service Co Of Oklahoma [Member]	Southwestern Electric Power Co [Member]	Common Stock [Member]	Common Stock [Member]Appalachian Power Co [Member]	Common Stock [Member]Indiana Michigan Power Co [Member]	Common Stock [Member]Ohio Power Co [Member]	Common Stock [Member]Public Service Co Of Oklahoma [Member]	Common Stock [Member]Southwestern Electric Power Co [Member]	Additional Paid-in Capital [Member]	Additional Paid-in Capital [Member]Appalachian Power Co [Member]	Additional Paid-in Capital [Member]Indiana Michigan Power Co [Member]	Additional Paid-in Capital [Member]Ohio Power Co [Member]	Additional Paid-in Capital [Member]Public Service Co Of Oklahoma [Member]	Additional Paid-in Capital [Member]Southwestern Electric Power Co [Member]	Retained Earnings [Member]	Retained Earnings [Member]Appalachian Power Co [Member]	Retained Earnings [Member]Indiana Michigan Power Co [Member]	Retained Earnings [Member]Ohio Power Co [Member]	Retained Earnings [Member]Public Service Co Of Oklahoma [Member]	Retained Earnings [Member]Southwestern Electric Power Co [Member]	Accumulated Other Comprehensive Income [Member]	Accumulated Other Comprehensive Income [Member]Appalachian Power Co [Member]	Accumulated Other Comprehensive Income [Member]Indiana Michigan Power Co [Member]	Accumulated Other Comprehensive Income [Member]Ohio Power Co [Member]	Accumulated Other Comprehensive Income [Member]Public Service Co Of Oklahoma [Member]	Accumulated Other Comprehensive Income [Member]Southwestern Electric Power Co [Member]	Noncontrolling Interests [Member]	Noncontrolling Interests [Member]Southwestern Electric Power Co [Member]
Beginning Balance at Dec. 31, 2013	$ 16,086,000	$ 3,229,432	$ 1,922,153	$ 1,625,265	$ 942,101	$ 2,055,917	$ 3,303,000	$ 260,458	$ 56,584	$ 321,201	$ 157,230	$ 135,660	$ 6,131,000	$ 1,809,562	$ 980,896	$ 663,782	$ 364,037	$ 674,606	$ 6,766,000	$ 1,156,461	$ 900,182	$ 633,203	$ 415,076	$ 1,253,617	$ (115,000)	$ 2,951	$ (15,509)	$ 7,079	$ 5,758	$ (8,444)	$ 1,000	$ 478
Beginning Balance, Shares at Dec. 31, 2013							508,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	29,000						$ 5,000						24,000
Issuance of Common Stock, Shares							1,000,000
Common Stock Dividends	(490,000)																		(488,000)
Common Stock Dividends		(40,000)	(75,000)	(35,000)		(50,000)														(40,000)	(75,000)	(35,000)		(50,000)
Common Stock Dividends						(2,309)																									(2,000)	(2,309)
Other Changes in Equity	(3,000)																		(6,000)												3,000
Net Income (Loss)																			950,000					53,557
Net Income (Loss) Attributable to Noncontrolling Interests	2,000					2,228																									2,000	2,228
Net Income (Loss)	952,000	138,098	114,423	117,309	30,897	55,785														138,098	114,423	117,309	30,897
Other Comprehensive Income (Loss)	11,000	(254)	861	(791)	(436)	600																			11,000	(254)	861	(791)	(436)	600
Ending Balance at Jun. 30, 2014	16,585,000	3,327,276	1,962,437	1,706,783	972,562	2,059,993	$ 3,308,000	260,458	56,584	321,201	157,230	135,660	6,155,000	1,809,562	980,896	663,782	364,037	674,606	7,222,000	1,254,559	939,605	715,512	445,973	1,257,174	(104,000)	2,697	(14,648)	6,288	5,322	(7,844)	4,000	397
Ending Balance, Shares at Jun. 30, 2014							509,000,000
Beginning Balance at Dec. 31, 2014	$ 16,824,000	3,366,928	1,953,949	1,980,210	$ 1,028,215	2,097,201	$ 3,313,000	260,458	56,584	321,201	157,230	135,660	6,204,000	1,809,562	980,896	838,782	364,037	674,606	7,406,000	1,291,876	930,829	814,625	502,005	1,293,986	(103,000)	5,032	(14,360)	5,602	4,943	(7,466)	4,000	415
Beginning Balance, Shares at Dec. 31, 2014	509,739,159				10,482,000		510,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of Common Stock, Value	$ 56,000						$ 8,000						48,000
Issuance of Common Stock, Shares							1,000,000
Common Stock Dividends	(522,000)																		(520,000)
Common Stock Dividends		(118,750)	(60,000)	(87,500)		(60,000)														(118,750)	(60,000)	(87,500)		(60,000)
Common Stock Dividends						(2,107)																									(2,000)	(2,107)
Other Changes in Equity	4,000												1,000																		3,000
Deferred State Income Tax Rate Adjustment	17,000												17,000
Net Income (Loss)																			1,059,000					104,174
Net Income (Loss) Attributable to Noncontrolling Interests	3,000					1,989																									3,000	1,989
Net Income (Loss)	1,062,000	200,845	123,255	113,119	$ 40,783	106,163														200,845	123,255	113,119	40,783
Other Comprehensive Income (Loss)	(4,000)	(785)	557	(686)	(380)	655																			(4,000)	(785)	557	(686)	(380)	655
Ending Balance at Jun. 30, 2015	$ 17,442,000	$ 3,448,238	$ 2,017,761	$ 2,005,143	$ 1,068,618	$ 2,141,912	$ 3,321,000	$ 260,458	$ 56,584	$ 321,201	$ 157,230	$ 135,660	$ 6,270,000	$ 1,809,562	$ 980,896	$ 838,782	$ 364,037	$ 674,606	$ 7,945,000	$ 1,373,971	$ 994,084	$ 840,244	$ 542,788	$ 1,338,160	(102,000)	$ 4,247	$ (13,803)	$ 4,916	$ 4,563	$ (6,811)	$ 8,000	$ 297
Ending Balance, Shares at Jun. 30, 2015	510,884,774				10,482,000		511,000,000
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Pension and OPEB Adjustment Related to Mitchell Plant	$ 5,000																								$ 5,000

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents		$ 195,000	$ 163,000
Other Temporary Investments		356,000	386,000
Accounts Receivable:
Customers		815,000	727,000
Accrued Unbilled Revenues		64,000	146,000
Pledged Accounts Receivable - AEP Credit		997,000	987,000
Miscellaneous		71,000	87,000
Allowance for Uncollectible Accounts		(27,000)	(21,000)
Total Accounts Receivable		1,920,000	1,926,000
Fuel		424,000	587,000
Materials and Supplies		736,000	738,000
Risk Management Assets		172,000	178,000
Regulatory Asset for Under-Recovered Fuel Costs		125,000	127,000
Margin Deposits		87,000	95,000
Prepayments and Other Current Assets		210,000	278,000
TOTAL CURRENT ASSETS		4,225,000	4,478,000
Property, Plant and Equipment
Generation		25,619,000	25,727,000
Transmission		13,020,000	12,433,000
Distribution		17,594,000	17,157,000
Other Property, Plant and Equipment		4,718,000	5,770,000
Construction Work in Progress		3,651,000	3,218,000
Total Property, Plant and Equipment		64,602,000	64,305,000
Accumulated Depreciation and Amortization		19,589,000	20,188,000
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		45,013,000	44,117,000
Other Noncurrent Assets
Regulatory Assets		5,021,000	4,264,000
Securitized Assets		1,931,000	2,072,000
Spent Nuclear Fuel and Decommissioning Trusts		2,106,000	2,096,000
Goodwill		91,000	91,000
Long-term Risk Management Assets		363,000	294,000
Deferred Charges and Other Noncurrent Assets		2,188,000	2,221,000
TOTAL OTHER NONCURRENT ASSETS		11,700,000	11,038,000
TOTAL ASSETS		60,938,000	59,633,000
Current Liabilities
Accounts Payable		1,236,000	1,287,000
Short-term Debt:
Securitized Debt for Receivables - AEP Credit	[1]	708,000	744,000
Other Short-term Debt		397,000	602,000
Total Short-term Debt		1,105,000	1,346,000
Long-term Debt Due Within One Year		1,817,000	2,503,000
Long-term Debt Due Within One Year - Affiliated		0	0
Risk Management Liabilities		78,000	92,000
Customer Deposits		335,000	324,000
Accrued Taxes		749,000	871,000
Accrued Interest		232,000	239,000
Regulatory Liability for Over-Recovered Fuel Costs		39,000	55,000
Other Current Liabilities		1,059,000	1,250,000
TOTAL CURRENT LIABILITIES		6,650,000	7,967,000
Noncurrent Liabilities
Long-term Debt		17,761,000	16,181,000
Long-term Risk Management Liabilities		174,000	131,000
Deferred Income Taxes		11,426,000	10,986,000
Regulatory Liabilities and Deferred Investment Tax Credits		3,850,000	3,892,000
Asset Retirement Obligations		2,038,000	1,951,000
Employee Benefits and Pension Obligations		509,000	630,000
Deferred Credits and Other Noncurrent Liabilities		1,088,000	1,071,000
TOTAL NONCURRENT LIABILITIES		36,846,000	34,842,000
TOTAL LIABILITIES		$ 43,496,000	$ 42,809,000
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 3,321,000	$ 3,313,000
Paid-in Capital		6,270,000	6,204,000
Retained Earnings		7,945,000	7,406,000
Accumulated Other Comprehensive Income (Loss)		(102,000)	(103,000)
TOTAL COMMON SHAREHOLDER'S EQUITY		17,434,000	16,820,000
Noncontrolling Interests		8,000	4,000
TOTAL EQUITY		17,442,000	16,824,000
TOTAL LIABILITIES AND EQUITY		60,938,000	59,633,000
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents		2,523	2,613
Restricted Cash for Securitized Funding		15,565	15,599
Advances to Affiliates		23,685	48,519
Accounts Receivable:
Customers		126,488	114,711
Affiliated Companies		54,790	67,294
Accrued Unbilled Revenues		43,102	58,022
Miscellaneous		1,843	1,956
Allowance for Uncollectible Accounts		(3,032)	(2,364)
Total Accounts Receivable		223,191	239,619
Fuel		92,073	113,386
Materials and Supplies		129,521	131,285
Risk Management Assets		38,877	23,792
Deferred Income Tax Benefits		3,491	23,955
Regulatory Asset for Under-Recovered Fuel Costs		83,558	66,076
Prepayments and Other Current Assets		18,122	13,660
TOTAL CURRENT ASSETS		630,606	678,504
Property, Plant and Equipment
Generation		6,215,900	6,824,029
Transmission		2,249,454	2,228,029
Distribution		3,314,816	3,258,306
Other Property, Plant and Equipment		384,861	373,520
Construction Work in Progress		459,307	321,495
Total Property, Plant and Equipment		12,624,338	13,005,379
Accumulated Depreciation and Amortization		3,396,158	3,823,664
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,228,180	9,181,715
Other Noncurrent Assets
Regulatory Assets		1,038,924	857,872
Securitized Assets		339,020	350,170
Long-term Risk Management Assets		3,002	4,891
Deferred Charges and Other Noncurrent Assets		154,587	159,230
TOTAL OTHER NONCURRENT ASSETS		1,535,533	1,372,163
TOTAL ASSETS		11,394,319	11,232,382
Current Liabilities
Advances from Affiliates		57,388	0
Accounts Payable		170,980	166,821
Affiliated Companies		67,380	80,602
Short-term Debt:
Long-term Debt Due Within One Year		252,410	552,212
Long-term Debt Due Within One Year - Affiliated		0	86,000
Risk Management Liabilities		9,159	11,017
Customer Deposits		76,867	71,766
Accrued Taxes		99,682	109,482
Accrued Interest		41,675	52,141
Other Current Liabilities		142,079	145,017
TOTAL CURRENT LIABILITIES		917,620	1,275,058
Noncurrent Liabilities
Long-term Debt		3,714,237	3,342,062
Long-term Risk Management Liabilities		1,448	2,057
Deferred Income Taxes		2,384,223	2,288,842
Regulatory Liabilities and Deferred Investment Tax Credits		661,932	652,867
Asset Retirement Obligations		118,310	122,300
Employee Benefits and Pension Obligations		117,780	127,980
Deferred Credits and Other Noncurrent Liabilities		30,531	54,288
TOTAL NONCURRENT LIABILITIES		7,028,461	6,590,396
TOTAL LIABILITIES		$ 7,946,081	$ 7,865,454
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 260,458	$ 260,458
Paid-in Capital		1,809,562	1,809,562
Retained Earnings		1,373,971	1,291,876
Accumulated Other Comprehensive Income (Loss)		4,247	5,032
TOTAL EQUITY		3,448,238	3,366,928
TOTAL LIABILITIES AND EQUITY		11,394,319	11,232,382
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents		1,317	1,020
Advances to Affiliates		13,504	13,481
Accounts Receivable:
Customers		73,208	56,978
Affiliated Companies		59,434	72,582
Accrued Unbilled Revenues		220	503
Miscellaneous		1,561	1,625
Allowance for Uncollectible Accounts		(375)	(494)
Total Accounts Receivable		134,048	131,194
Fuel		23,884	54,623
Materials and Supplies		189,022	201,089
Risk Management Assets		16,514	22,328
Accrued Tax Benefits		28,457	24,788
Prepayments and Other Current Assets		28,566	27,968
TOTAL CURRENT ASSETS		435,312	476,491
Property, Plant and Equipment
Generation		3,931,860	3,741,831
Transmission		1,375,436	1,358,419
Distribution		1,735,290	1,698,409
Other Property, Plant and Equipment		746,227	1,490,820
Construction Work in Progress		437,078	537,237
Total Property, Plant and Equipment		8,225,891	8,826,716
Accumulated Depreciation and Amortization		3,049,243	3,410,341
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		5,176,648	5,416,375
Other Noncurrent Assets
Regulatory Assets		839,110	536,152
Spent Nuclear Fuel and Decommissioning Trusts		2,106,090	2,095,732
Long-term Risk Management Assets		2,026	3,317
Deferred Charges and Other Noncurrent Assets		127,922	137,209
TOTAL OTHER NONCURRENT ASSETS		3,075,148	2,772,410
TOTAL ASSETS		8,687,108	8,665,276
Current Liabilities
Advances from Affiliates		140,658	142,501
Accounts Payable		117,949	168,294
Affiliated Companies		75,328	76,010
Short-term Debt:
Long-term Debt Due Within One Year		312,370	382,187
Risk Management Liabilities		4,493	5,223
Customer Deposits		35,224	35,206
Accrued Taxes		68,633	72,742
Accrued Interest		26,888	26,677
Obligations Under Capital Leases		42,186	42,050
Other Current Liabilities		112,701	150,566
TOTAL CURRENT LIABILITIES		936,430	1,101,456
Noncurrent Liabilities
Long-term Debt		1,776,543	1,645,210
Long-term Risk Management Liabilities		982	1,395
Deferred Income Taxes		1,332,635	1,264,167
Regulatory Liabilities and Deferred Investment Tax Credits		1,134,679	1,199,694
Asset Retirement Obligations		1,365,572	1,337,179
Deferred Credits and Other Noncurrent Liabilities		122,506	162,226
TOTAL NONCURRENT LIABILITIES		5,732,917	5,609,871
TOTAL LIABILITIES		$ 6,669,347	$ 6,711,327
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 56,584	$ 56,584
Paid-in Capital		980,896	980,896
Retained Earnings		994,084	930,829
Accumulated Other Comprehensive Income (Loss)		(13,803)	(14,360)
TOTAL EQUITY		2,017,761	1,953,949
TOTAL LIABILITIES AND EQUITY		8,687,108	8,665,276
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents		3,439	2,870
Restricted Cash for Securitized Funding		28,699	28,687
Advances to Affiliates		187,812	312,473
Accounts Receivable:
Customers		45,450	57,906
Affiliated Companies		91,434	79,822
Accrued Unbilled Revenues		803	35,755
Miscellaneous		720	927
Allowance for Uncollectible Accounts		(165)	(171)
Total Accounts Receivable		138,242	174,239
Notes Receivable Due Within One Year - Affiliated		0	86,000
Materials and Supplies		75,595	60,909
Risk Management Assets		0	7,242
Deferred Income Tax Benefits		44,336	49,306
Accrued Tax Benefits		5,699	6,100
Prepayments and Other Current Assets		8,705	8,997
TOTAL CURRENT ASSETS		492,527	736,823
Property, Plant and Equipment
Transmission		2,159,276	2,104,613
Distribution		4,177,897	4,087,601
Other Property, Plant and Equipment		434,887	390,848
Construction Work in Progress		222,943	218,667
Total Property, Plant and Equipment		6,995,003	6,801,729
Accumulated Depreciation and Amortization		2,070,583	2,038,120
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		4,924,420	4,763,609
Other Noncurrent Assets
Notes Receivable - Affiliated		32,245	32,245
Regulatory Assets		1,237,933	1,318,939
Securitized Assets		97,849	109,999
Long-term Risk Management Assets		44,056	45,102
Deferred Charges and Other Noncurrent Assets		170,043	264,150
TOTAL OTHER NONCURRENT ASSETS		1,582,126	1,770,435
TOTAL ASSETS		6,999,073	7,270,867
Current Liabilities
Accounts Payable		166,189	145,328
Affiliated Companies		85,996	172,741
Short-term Debt:
Long-term Debt Due Within One Year		396,045	131,497
Risk Management Liabilities		2,010	1,943
Customer Deposits		60,038	53,922
Accrued Taxes		320,688	420,772
Accrued Interest		33,242	34,279
Other Current Liabilities		128,328	179,093
TOTAL CURRENT LIABILITIES		1,192,536	1,139,575
Noncurrent Liabilities
Long-term Debt		1,793,114	2,165,626
Long-term Risk Management Liabilities		4,573	3,013
Deferred Income Taxes		1,414,723	1,405,620
Regulatory Liabilities and Deferred Investment Tax Credits		530,224	514,691
Employee Benefits and Pension Obligations		28,498	36,662
Deferred Credits and Other Noncurrent Liabilities		30,262	25,470
TOTAL NONCURRENT LIABILITIES		3,801,394	4,151,082
TOTAL LIABILITIES		$ 4,993,930	$ 5,290,657
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 321,201	$ 321,201
Paid-in Capital		838,782	838,782
Retained Earnings		840,244	814,625
Accumulated Other Comprehensive Income (Loss)		4,916	5,602
TOTAL EQUITY		2,005,143	1,980,210
TOTAL LIABILITIES AND EQUITY		6,999,073	7,270,867
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents		1,273	1,352
Advances to Affiliates		64,212	0
Accounts Receivable:
Customers		36,527	28,448
Affiliated Companies		22,410	22,114
Miscellaneous		3,549	6,026
Allowance for Uncollectible Accounts		(56)	(147)
Total Accounts Receivable		62,430	56,441
Fuel		14,584	16,436
Materials and Supplies		53,195	50,880
Risk Management Assets		1,731	0
Deferred Income Tax Benefits		5,182	0
Accrued Tax Benefits		27,226	24,369
Regulatory Asset for Under-Recovered Fuel Costs		0	35,699
Prepayments and Other Current Assets		4,802	6,524
TOTAL CURRENT ASSETS		234,635	191,701
Property, Plant and Equipment
Generation		1,292,305	1,264,724
Transmission		798,209	788,911
Distribution		2,162,261	2,080,221
Other Property, Plant and Equipment		432,397	421,568
Construction Work in Progress		244,404	204,753
Total Property, Plant and Equipment		4,929,576	4,760,177
Accumulated Depreciation and Amortization		1,363,314	1,319,554
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,566,262	3,440,623
Other Noncurrent Assets
Regulatory Assets		170,834	154,327
Long-term Risk Management Assets		29	0
Employee Benefits and Pension Assets		20,583	19,335
Deferred Charges and Other Noncurrent Assets		23,711	7,557
TOTAL OTHER NONCURRENT ASSETS		215,157	181,219
TOTAL ASSETS		4,016,054	3,813,543
Current Liabilities
Advances from Affiliates		0	154,249
Accounts Payable		89,073	92,672
Affiliated Companies		55,424	51,744
Short-term Debt:
Long-term Debt Due Within One Year		434	427
Risk Management Liabilities		129	918
Customer Deposits		50,443	48,700
Accrued Taxes		36,266	20,887
Accrued Interest		16,142	12,699
Regulatory Liability for Over-Recovered Fuel Costs		15,894	0
Other Current Liabilities		43,867	58,878
TOTAL CURRENT LIABILITIES		307,672	441,174
Noncurrent Liabilities
Long-term Debt		1,290,561	1,040,609
Deferred Income Taxes		937,651	898,352
Regulatory Liabilities and Deferred Investment Tax Credits		335,164	334,479
Asset Retirement Obligations		41,980	37,030
Employee Benefits and Pension Obligations		15,423	20,095
Deferred Credits and Other Noncurrent Liabilities		18,985	13,589
TOTAL NONCURRENT LIABILITIES		2,639,764	2,344,154
TOTAL LIABILITIES		$ 2,947,436	$ 2,785,328
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 157,230	$ 157,230
Paid-in Capital		364,037	364,037
Retained Earnings		542,788	502,005
Accumulated Other Comprehensive Income (Loss)		4,563	4,943
TOTAL EQUITY		1,068,618	1,028,215
TOTAL LIABILITIES AND EQUITY		4,016,054	3,813,543
Southwestern Electric Power Co [Member]
Current Assets
Cash and Cash Equivalents		8,017	14,356
Advances to Affiliates		179,709	41,033
Accounts Receivable:
Customers		72,169	46,738
Affiliated Companies		24,986	37,114
Miscellaneous		26,675	25,625
Allowance for Uncollectible Accounts		(39)	(516)
Total Accounts Receivable		123,791	108,961
Fuel		105,171	116,955
Materials and Supplies		73,297	73,666
Risk Management Assets		2,077	31
Deferred Income Tax Benefits		9,610	9,041
Accrued Tax Benefits		9,423	15,408
Regulatory Asset for Under-Recovered Fuel Costs		19,118	24,024
Prepayments and Other Current Assets		23,912	25,779
TOTAL CURRENT ASSETS		554,125	429,254
Property, Plant and Equipment
Generation		3,927,856	3,864,543
Transmission		1,344,858	1,300,729
Distribution		1,928,523	1,894,572
Other Property, Plant and Equipment		891,788	878,753
Construction Work in Progress		577,984	471,980
Total Property, Plant and Equipment		8,671,009	8,410,577
Accumulated Depreciation and Amortization		2,579,758	2,503,290
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		6,091,251	5,907,287
Other Noncurrent Assets
Regulatory Assets		417,551	393,602
Long-term Risk Management Assets		33	0
Deferred Charges and Other Noncurrent Assets		120,330	86,750
TOTAL OTHER NONCURRENT ASSETS		537,914	480,352
TOTAL ASSETS		7,183,290	6,816,893
Current Liabilities
Accounts Payable		138,971	175,109
Affiliated Companies		82,129	67,410
Short-term Debt:
Long-term Debt Due Within One Year		153,250	306,750
Risk Management Liabilities		2,523	1,082
Customer Deposits		60,741	59,903
Accrued Taxes		74,559	43,965
Accrued Interest		46,139	44,328
Obligations Under Capital Leases		17,358	17,557
Other Current Liabilities		62,108	104,553
TOTAL CURRENT LIABILITIES		637,778	820,657
Noncurrent Liabilities
Long-term Debt		2,282,228	1,833,687
Deferred Income Taxes		1,397,455	1,351,111
Regulatory Liabilities and Deferred Investment Tax Credits		460,854	458,530
Asset Retirement Obligations		107,688	92,015
Employee Benefits and Pension Obligations		24,496	25,374
Obligations Under Capital Leases		83,245	91,044
Deferred Credits and Other Noncurrent Liabilities		47,634	47,274
TOTAL NONCURRENT LIABILITIES		4,403,600	3,899,035
TOTAL LIABILITIES		$ 5,041,378	$ 4,719,692
Rate Matters
Commitments and Contingencies
Equity
Common Stock		$ 135,660	$ 135,660
Paid-in Capital		674,606	674,606
Retained Earnings		1,338,160	1,293,986
Accumulated Other Comprehensive Income (Loss)		(6,811)	(7,466)
TOTAL COMMON SHAREHOLDER'S EQUITY		2,141,615	2,096,786
Noncontrolling Interests		297	415
TOTAL EQUITY		2,141,912	2,097,201
TOTAL LIABILITIES AND EQUITY		$ 7,183,290	$ 6,816,893
[1]	Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance

Condensed Consolidated Balance7

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Current Assets
Cash and Cash Equivalents	$ 195,000	$ 163,000
Other Temporary Investments	356,000	386,000
Fuel	424,000	587,000
Property, Plant and Equipment
Other Property, Plant and Equipment	4,718,000	5,770,000
Accumulated Depreciation and Amortization	19,589,000	20,188,000
Current Liabilities
Long-term Debt Due Within One Year	1,817,000	2,503,000
Noncurrent Liabilities
Long-term Debt	$ 17,761,000	$ 16,181,000
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	510,884,774	509,739,159
Treasury Stock, Shares	20,336,592	20,336,592
Appalachian Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 2,523	$ 2,613
Fuel	92,073	113,386
Property, Plant and Equipment
Other Property, Plant and Equipment	384,861	373,520
Accumulated Depreciation and Amortization	3,396,158	3,823,664
Current Liabilities
Long-term Debt Due Within One Year	252,410	552,212
Noncurrent Liabilities
Long-term Debt	$ 3,714,237	$ 3,342,062
Equity
Common Stock, Shares Authorized	30,000,000	30,000,000
Common Stock, Shares Outstanding	13,499,500	13,499,500
Indiana Michigan Power Co [Member]
Current Assets
Cash and Cash Equivalents	$ 1,317	$ 1,020
Fuel	23,884	54,623
Property, Plant and Equipment
Other Property, Plant and Equipment	746,227	1,490,820
Accumulated Depreciation and Amortization	3,049,243	3,410,341
Current Liabilities
Long-term Debt Due Within One Year	312,370	382,187
Noncurrent Liabilities
Long-term Debt	$ 1,776,543	$ 1,645,210
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	$ 109,242	$ 85,657
Ohio Power Co [Member]
Current Assets
Cash and Cash Equivalents	3,439	2,870
Property, Plant and Equipment
Other Property, Plant and Equipment	434,887	390,848
Accumulated Depreciation and Amortization	2,070,583	2,038,120
Current Liabilities
Long-term Debt Due Within One Year	396,045	131,497
Noncurrent Liabilities
Long-term Debt	$ 1,793,114	$ 2,165,626
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	$ 45,973	$ 45,427
Noncurrent Liabilities
Long-term Debt	164,295	187,041
Public Service Co Of Oklahoma [Member]
Current Assets
Cash and Cash Equivalents	1,273	1,352
Fuel	14,584	16,436
Property, Plant and Equipment
Other Property, Plant and Equipment	432,397	421,568
Accumulated Depreciation and Amortization	1,363,314	1,319,554
Current Liabilities
Long-term Debt Due Within One Year	434	427
Noncurrent Liabilities
Long-term Debt	$ 1,290,561	$ 1,040,609
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	$ 8,017	$ 14,356
Fuel	105,171	116,955
Property, Plant and Equipment
Other Property, Plant and Equipment	891,788	878,753
Accumulated Depreciation and Amortization	2,579,758	2,503,290
Current Liabilities
Long-term Debt Due Within One Year	153,250	306,750
Noncurrent Liabilities
Long-term Debt	$ 2,282,228	$ 1,833,687
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	$ 6,436	$ 12,695
Fuel	30,020	38,920
Property, Plant and Equipment
Other Property, Plant and Equipment	291,642	288,183
Accumulated Depreciation and Amortization	149,588	142,983
AEP Subsidiaries [Member]
Current Assets
Other Temporary Investments	344,000	371,000
Current Liabilities
Long-term Debt Due Within One Year	463,000	431,000
Noncurrent Liabilities
Long-term Debt	$ 2,114,000	$ 2,260,000

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Cash Flows - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Operating Activities
Net Income (Loss)	$ 1,062,000	$ 952,000
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	1,011,000	934,000
Deferred Income Taxes	453,000	410,000
Carrying Costs Income	(17,000)	(15,000)
Allowance for Equity Funds Used During Construction	(64,000)	(47,000)
Mark-to-Market of Risk Management Contracts	(41,000)	9,000
Amortization of Nuclear Fuel	66,000	79,000
Pension Contributions to Qualified Plan Trust	(93,000)	(71,000)
Property Taxes	102,000	92,000
Fuel Over/Under-Recovery, Net	22,000	(105,000)
Deferral of Ohio Capacity Costs, Net	(1,000)	(99,000)
Change in Other Noncurrent Assets	(91,000)	11,000
Change in Other Noncurrent Liabilities	12,000	132,000
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	12,000	(73,000)
Fuel, Materials and Supplies	149,000	207,000
Accounts Payable	(10,000)	(39,000)
Accrued Taxes, Net	(115,000)	(86,000)
Other Current Assets	22,000	(3,000)
Other Current Liabilities	(276,000)	(91,000)
Net Cash Flows from (Used for) Operating Activities	2,203,000	2,197,000
Investing Activities
Construction Expenditures	(2,182,000)	(1,883,000)
Change in Other Temporary Investments, Net	30,000	(24,000)
Purchases of Investment Securities	(541,000)	(510,000)
Sales of Investment Securities	516,000	483,000
Acquisitions of Nuclear Fuel	(52,000)	(58,000)
Acquisitions of Assets/Businesses	(2,000)	(45,000)
Other Investing Activities	41,000	(31,000)
Net Cash Flows from (Used for) Investing Activities	(2,190,000)	(2,068,000)
Financing Activities
Issuance of Common Stock, Net	56,000	29,000
Issuance of Long-term Debt	2,603,000	939,000
Change in Short-term Debt, Net	(241,000)	725,000
Retirement of Long-term Debt	(1,727,000)	(1,205,000)
Make Whole Premium on Extinguishment of Long-term Debt	(93,000)	0
Principal Payments for Capital Lease Obligations	(57,000)	(60,000)
Dividends Paid on Common Stock	(522,000)	(490,000)
Other Financing Activities	0	5,000
Net Cash Flows from (Used for) Financing Activities	19,000	(57,000)
Net Increase (Decrease) in Cash and Cash Equivalents	32,000	72,000
Cash and Cash Equivalents at Beginning of Period	163,000	118,000
Cash and Cash Equivalents at End of Period	195,000	190,000
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	431,000	422,000
Net Cash Paid (Received) for Income Taxes	98,000	63,000
Noncash Acquisitions Under Capital Leases	76,000	33,000
Construction Expenditures Included in Current Liabilities as of June 30,	543,000	432,000
Construction Expenditures Included in Noncurrent Liabilities as of June 30,	66,000	0
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	0	42,000
Appalachian Power Co [Member]
Operating Activities
Net Income (Loss)	200,845	138,098
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	196,440	200,236
Deferred Income Taxes	122,498	90,236
Carrying Costs Income	(710)	1,612
Allowance for Equity Funds Used During Construction	(6,905)	(2,860)
Mark-to-Market of Risk Management Contracts	(15,664)	(6,025)
Pension Contributions to Qualified Plan Trust	(9,981)	(8,963)
Fuel Over/Under-Recovery, Net	(15,297)	(108,943)
Change in Other Noncurrent Assets	(1,845)	2,861
Change in Other Noncurrent Liabilities	(10,436)	23,626
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	18,911	93,553
Fuel, Materials and Supplies	15,489	69,120
Accounts Payable	(20,590)	(46,812)
Accrued Taxes, Net	(11,450)	(9,690)
Other Current Assets	(2,212)	(2,294)
Other Current Liabilities	(21,028)	(10,469)
Net Cash Flows from (Used for) Operating Activities	438,065	423,286
Investing Activities
Construction Expenditures	(293,100)	(224,879)
Change in Advances to Affiliates, Net	24,834	63,691
Other Investing Activities	7,012	(14,754)
Net Cash Flows from (Used for) Investing Activities	(261,254)	(175,942)
Financing Activities
Issuance of Long-term Debt	726,330	295,042
Change in Advances from Affiliates, Net	57,387	0
Retirement of Long-term Debt	(661,055)	(500,016)
Make Whole Premium on Extinguishment of Long-term Debt	(92,658)	0
Repayments of Related Party Debt	(86,000)	0
Principal Payments for Capital Lease Obligations	(2,571)	(2,904)
Dividends Paid on Common Stock	(118,750)	(40,000)
Other Financing Activities	416	1,002
Net Cash Flows from (Used for) Financing Activities	(176,901)	(246,876)
Net Increase (Decrease) in Cash and Cash Equivalents	(90)	468
Cash and Cash Equivalents at Beginning of Period	2,613	2,745
Cash and Cash Equivalents at End of Period	2,523	3,213
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	105,616	96,564
Net Cash Paid (Received) for Income Taxes	5,226	1,280
Noncash Acquisitions Under Capital Leases	1,880	3,133
Construction Expenditures Included in Current Liabilities as of June 30,	81,624	50,052
Indiana Michigan Power Co [Member]
Operating Activities
Net Income (Loss)	123,255	114,423
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	100,947	99,477
Deferred Income Taxes	48,011	17,499
Amortization (Deferral) of Incremental Nuclear Refueling Outage Expense, Net	(11,605)	28,358
Allowance for Equity Funds Used During Construction	(6,950)	(8,768)
Mark-to-Market of Risk Management Contracts	5,962	(4,378)
Amortization of Nuclear Fuel	65,514	78,560
Fuel Over/Under-Recovery, Net	(15,089)	14,567
Change in Other Noncurrent Assets	31,547	(42,263)
Change in Other Noncurrent Liabilities	(25,024)	44,269
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(2,250)	45,666
Fuel, Materials and Supplies	31,084	4,668
Accounts Payable	6,764	(26,859)
Accrued Taxes, Net	(7,778)	17,381
Other Current Assets	5,214	9,815
Other Current Liabilities	(37,109)	(22,913)
Net Cash Flows from (Used for) Operating Activities	312,493	369,502
Investing Activities
Construction Expenditures	(221,587)	(224,937)
Change in Advances to Affiliates, Net	(23)	42,357
Purchases of Investment Securities	(540,711)	(508,835)
Sales of Investment Securities	515,784	482,534
Acquisitions of Nuclear Fuel	(52,171)	(57,991)
Other Investing Activities	7,399	9,299
Net Cash Flows from (Used for) Investing Activities	(291,309)	(257,573)
Financing Activities
Issuance of Long-term Debt	210,702	99,419
Change in Advances from Affiliates, Net	(1,843)	47,353
Retirement of Long-term Debt	(150,077)	(160,292)
Principal Payments for Capital Lease Obligations	(20,181)	(23,622)
Dividends Paid on Common Stock	(60,000)	(75,000)
Other Financing Activities	512	554
Net Cash Flows from (Used for) Financing Activities	(20,887)	(111,588)
Net Increase (Decrease) in Cash and Cash Equivalents	297	341
Cash and Cash Equivalents at Beginning of Period	1,020	1,317
Cash and Cash Equivalents at End of Period	1,317	1,658
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	42,252	42,779
Net Cash Paid (Received) for Income Taxes	17,066	13,206
Noncash Acquisitions Under Capital Leases	1,384	3,918
Construction Expenditures Included in Current Liabilities as of June 30,	53,118	59,759
Acquisition of Nuclear Fuel Included in Current Liabilities as of June 30,	30	42,076
Expected Reimbursement for Spent Nuclear Fuel Dry Cask Storage	432	2,444
Ohio Power Co [Member]
Operating Activities
Net Income (Loss)	113,119	117,309
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	114,852	110,184
Amortization of Generation Deferrals	66,755	56,163
Deferred Income Taxes	15,527	41,576
Carrying Costs Income	(11,613)	(13,988)
Allowance for Equity Funds Used During Construction	(4,787)	(3,068)
Mark-to-Market of Risk Management Contracts	9,916	(6,379)
Pension Contributions to Qualified Plan Trust	(7,671)	(6,547)
Property Taxes	96,279	100,522
Fuel Over/Under-Recovery, Net	(22,931)	28,671
Deferral of Ohio Capacity Costs, Net	(30,662)	(120,743)
Change in Other Noncurrent Assets	23,865	13,281
Change in Other Noncurrent Liabilities	22,543	46,213
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	38,230	(2,256)
Fuel, Materials and Supplies	(14,687)	(4,205)
Accounts Payable	(68,105)	(70,228)
Customer Deposits	6,116	480
Accrued Taxes, Net	(99,683)	(138,584)
Other Current Assets	(787)	(560)
Other Current Liabilities	(30,230)	(24,522)
Net Cash Flows from (Used for) Operating Activities	216,046	123,319
Investing Activities
Construction Expenditures	(236,048)	(213,974)
Change in Restricted Cash for Securitized Funding	(12)	(23,616)
Change in Advances to Affiliates, Net	124,661	339,070
Proceeds from Notes Receivable Affiliated	86,000	139,450
Other Investing Activities	6,439	3,570
Net Cash Flows from (Used for) Investing Activities	(18,960)	244,500
Financing Activities
Change in Advances from Affiliates, Net	0	34,723
Retirement of Long-term Debt	(108,238)	(364,498)
Principal Payments for Capital Lease Obligations	(1,937)	(2,562)
Dividends Paid on Common Stock	(87,500)	(35,000)
Other Financing Activities	1,158	989
Net Cash Flows from (Used for) Financing Activities	(196,517)	(366,348)
Net Increase (Decrease) in Cash and Cash Equivalents	569	1,471
Cash and Cash Equivalents at Beginning of Period	2,870	3,004
Cash and Cash Equivalents at End of Period	3,439	4,475
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	61,278	69,127
Net Cash Paid (Received) for Income Taxes	20,500	10,863
Noncash Acquisitions Under Capital Leases	1,727	3,754
Construction Expenditures Included in Current Liabilities as of June 30,	42,222	40,878
Public Service Co Of Oklahoma [Member]
Operating Activities
Net Income (Loss)	40,783	30,897
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	59,316	48,589
Deferred Income Taxes	24,672	28,493
Allowance for Equity Funds Used During Construction	(3,610)	(2,021)
Mark-to-Market of Risk Management Contracts	(2,549)	578
Pension Contributions to Qualified Plan Trust	(5,795)	(4,439)
Property Taxes	(16,099)	(15,940)
Fuel Over/Under-Recovery, Net	51,593	(38,554)
Change in Other Noncurrent Assets	(14,048)	(10,411)
Change in Other Noncurrent Liabilities	4,492	(3,079)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(5,989)	(4,382)
Fuel, Materials and Supplies	(463)	3,330
Accounts Payable	5,482	959
Accrued Taxes, Net	12,522	(1,116)
Other Current Assets	644	(1,386)
Other Current Liabilities	(3,582)	9,888
Net Cash Flows from (Used for) Operating Activities	147,369	41,406
Investing Activities
Construction Expenditures	(180,164)	(170,565)
Change in Advances to Affiliates, Net	(64,212)	0
Other Investing Activities	3,636	1,560
Net Cash Flows from (Used for) Investing Activities	(240,740)	(169,005)
Financing Activities
Issuance of Long-term Debt	248,785	74,975
Change in Advances from Affiliates, Net	(154,249)	88,028
Retirement of Long-term Debt	(212)	(33,906)
Principal Payments for Capital Lease Obligations	(1,762)	(1,731)
Other Financing Activities	730	583
Net Cash Flows from (Used for) Financing Activities	93,292	127,949
Net Increase (Decrease) in Cash and Cash Equivalents	(79)	350
Cash and Cash Equivalents at Beginning of Period	1,352	1,277
Cash and Cash Equivalents at End of Period	1,273	1,627
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	25,353	26,684
Net Cash Paid (Received) for Income Taxes	4,228	2,463
Noncash Acquisitions Under Capital Leases	1,389	1,190
Construction Expenditures Included in Current Liabilities as of June 30,	30,881	40,150
Southwestern Electric Power Co [Member]
Operating Activities
Net Income (Loss)	106,163	55,785
Adjustments to Reconcile Net Income to Net Cash Flows from (Used for) Operating Activities:
Depreciation and Amortization	94,918	91,525
Deferred Income Taxes	31,457	179,336
Allowance for Equity Funds Used During Construction	(11,111)	(4,278)
Mark-to-Market of Risk Management Contracts	(639)	593
Pension Contributions to Qualified Plan Trust	(8,052)	(3,832)
Property Taxes	(26,093)	(25,053)
Fuel Over/Under-Recovery, Net	4,906	(18,825)
Change in Other Noncurrent Assets	(4,443)	8,034
Change in Other Noncurrent Liabilities	(454)	(3,464)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	(14,732)	21,194
Fuel, Materials and Supplies	12,153	22,914
Accounts Payable	(3,174)	8,186
Accrued Taxes, Net	36,579	(108,460)
Other Current Assets	1,428	(3,310)
Other Current Liabilities	(40,627)	(10,700)
Net Cash Flows from (Used for) Operating Activities	178,279	209,645
Investing Activities
Construction Expenditures	(268,423)	(220,968)
Change in Advances to Affiliates, Net	(138,676)	0
Other Investing Activities	2,138	3,394
Net Cash Flows from (Used for) Investing Activities	(404,961)	(217,574)
Financing Activities
Issuance of Long-term Debt	445,949	0
Change in Advances from Affiliates, Net	0	69,918
Retirement of Long-term Debt	(155,125)	(1,625)
Principal Payments for Capital Lease Obligations	(9,138)	(9,156)
Dividends Paid on Common Stock	(60,000)	(50,000)
Dividends Paid on Common Stock	(2,107)	(2,309)
Other Financing Activities	764	831
Net Cash Flows from (Used for) Financing Activities	220,343	7,659
Net Increase (Decrease) in Cash and Cash Equivalents	(6,339)	(270)
Cash and Cash Equivalents at Beginning of Period	14,356	17,241
Cash and Cash Equivalents at End of Period	8,017	16,971
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	55,799	60,001
Net Cash Paid (Received) for Income Taxes	9,628	(7,556)
Noncash Acquisitions Under Capital Leases	1,162	3,354
Construction Expenditures Included in Current Liabilities as of June 30,	$ 73,626	$ 63,813

Significant Accounting Matters

Significant Accounting Matters	6 Months Ended
	Jun. 30, 2015
Significant Accounting Matters	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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2014 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 20, 2015 . 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, KPCo and WPCo 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 on January 1, 2014, 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 EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards. The following tables present our basic and diluted EPS calculations included on our condensed statements of income: Three Months Ended June 30, 2015 2014 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 430 $ 390 Weighted Average Number of Basic Shares Outstanding 490.2 $ 0.88 488.3 $ 0.80 Weighted Average Dilutive Effect of Restricted Stock Units 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 490.5 $ 0.88 488.5 $ 0.80 Six Months Ended June 30, 2015 2014 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 1,059 $ 950 Weighted Average Number of Basic Shares Outstanding 489.9 $ 2.16 488.1 $ 1.95 Weighted Average Dilutive Effect of Restricted Stock Units 0.3 — 0.3 — Weighted Average Number of Diluted Shares Outstanding 490.2 $ 2.16 488.4 $ 1.95 There were no antidilutive shares outstanding as of June 30, 2015 and 2014.
Appalachian Power Co [Member]
Significant Accounting Matters	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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .
Indiana Michigan Power Co [Member]
Significant Accounting Matters	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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .
Ohio Power Co [Member]
Significant Accounting Matters	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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .
Public Service Co Of Oklahoma [Member]
Significant Accounting Matters	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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .
Southwestern Electric Power Co [Member]
Significant Accounting Matters	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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .

New Accounting Pronouncements

New Accounting Pronouncements	6 Months Ended
	Jun. 30, 2015
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, we review the new accounting literature to determine its relevance, if any, to our business. The following final pronouncements 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. 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 adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. We plan to adopt ASU 2014-09 effective January 1, 2017. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. We plan to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. We include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We intend to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Customer's Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. We are analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. We plan to adopt ASU 2015-11 effective January 1, 2017.
Appalachian Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2017. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017.
Indiana Michigan Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2017. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017.
Ohio Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2017. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017.
Public Service Co Of Oklahoma [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2017. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017.
Southwestern Electric Power Co [Member]
New Accounting Pronouncements	NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of final pronouncements, management reviews the new accounting literature to determine its relevance, if any, to the Registrant Subsidiaries’ business. The following final pronouncements will impact the financial statements. ASU 2014-08 “Presentation of Financial Statements and Property, Plant and Equipment” (ASU 2014-08) In April 2014, the FASB issued ASU 2014-08 changing the presentation of discontinued operations on the statements of income and other requirements for reporting discontinued operations. Under the new standard, a disposal of a component or a group of components of an entity is required to be reported in discontinued operations if the disposal represents a strategic shift that has (or will have) a major effect on an entity’s operations and financial results when the component meets the criteria to be classified as held-for-sale or is disposed. The amendments in this update also require additional disclosures about discontinued operations and disposal of an individually significant component of an entity that does not qualify for discontinued operations. This standard must be prospectively applied to all reporting periods presented in financial reports issued after the effective date. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2014. If applicable, this standard will change the presentation of financial statements but will not affect the calculation of net income, comprehensive income or earnings per share. Management adopted ASU 2014-08 effective January 1, 2015. There were no events requiring the application of this new accounting guidance. ASU 2014-09 “Revenue from Contracts with Customers” (ASU 2014-09) In May 2014, the FASB issued ASU 2014-09 clarifying the method used to determine the timing and requirements for revenue recognition on the statements of income. Under the new standard, an entity must identify the performance obligations in a contract, the transaction price and allocate the price to specific performance obligations to recognize the revenue when the obligation is completed. The amendments in this update also require disclosure of sufficient information to allow users to understand the nature, amount, timing and uncertainty of revenue and cash flow arising from contracts. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016. Early adoption is not permitted. As applicable, this standard may change the amount of revenue recognized in the income statements in each reporting period. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on revenue or net income. Management plans to adopt ASU 2014-09 effective January 1, 2017. ASU 2015-01 “Income Statement – Extraordinary and Unusual Items” (ASU 2015-01) In January 2015, the FASB issued ASU 2015-01 eliminating the concept of extraordinary items for presentation on the face of the income statement. Under the new standard, a material event or transaction that is unusual in nature, infrequent or both shall be reported as a separate component of income from continuing operations. Alternatively, it may be disclosed in the notes to financial statements. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015. Early adoption is permitted if applied from the beginning of a fiscal year. As applicable, this standard may change the presentation of amounts in the income statements. Management plans to adopt ASU 2015-01 effective January 1, 2016. ASU 2015-03 “Simplifying the Presentation of Debt Issuance Costs” (ASU 2015-03) In April 2015, the FASB issued ASU 2015-03 to simplify the presentation of debt issuance costs on the balance sheets. Under the new standard, debt issuance costs related to a recognized debt liability will be presented on the balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with discounts. The Registrant Subsidiaries include debt issuance costs in Deferred Charges and Other Noncurrent Assets on the condensed balance sheets. Debt issuance costs represent less than 1% of total long-term debt. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management intends to early adopt ASU 2015-03 for the 2015 Form 10-K. ASU 2015-05 “Accounting for Fees Paid in a Cloud Computing Arrangement” (ASU 2015-05) In April 2015, the FASB issued ASU 2015-05 to provide guidance to customers about whether a cloud computing arrangement includes a software license. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2015 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-05 effective January 1, 2016. ASU 2015-11 “Simplifying the Measurement of Inventory” (ASU 2015-11) In July 2015, the FASB issued ASU 2015-11 to simplify the guidance on the subsequent measurement of inventory, excluding inventory measured using last-in, first out or the retail inventory method. Under the new standard, inventory should be at the lower of cost and net realizable value. The new accounting guidance is effective for interim and annual periods beginning after December 15, 2016 with early adoption permitted. Management is analyzing the impact of this new standard and, at this time, cannot estimate the impact of adoption on net income. Management plans to adopt ASU 2015-11 effective January 1, 2017.

Comprehensive Income

Comprehensive Income	6 Months Ended
	Jun. 30, 2015
Comprehensive Income	COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and six months ended June 30, 2015 and 2014 . 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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2015 $ (6 ) $ (18 ) $ 9 $ (88 ) $ (103 ) Change in Fair Value Recognized in AOCI (1 ) — (1 ) — (2 ) Amounts Reclassified from AOCI 2 — — 1 3 Net Current Period Other Comprehensive Income (Loss) 1 — (1 ) 1 1 Balance in AOCI as of June 30, 2015 $ (5 ) $ (18 ) $ 8 $ (87 ) $ (102 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2014 $ 4 $ (22 ) $ 7 $ (98 ) $ (109 ) Change in Fair Value Recognized in AOCI 3 — 1 — 4 Amounts Reclassified from AOCI (1 ) 1 — 1 1 Net Current Period Other Comprehensive Income 2 1 1 1 5 Balance in AOCI as of June 30, 2014 $ 6 $ (21 ) $ 8 $ (97 ) $ (104 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1 $ (19 ) $ 8 $ (93 ) $ (103 ) Change in Fair Value Recognized in AOCI 2 — — — 2 Amounts Reclassified from AOCI (8 ) 1 — 1 (6 ) Net Current Period Other Comprehensive Income (Loss) (6 ) 1 — 1 (4 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5 5 Balance in AOCI as of June 30, 2015 $ (5 ) $ (18 ) $ 8 $ (87 ) $ (102 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (23 ) $ 7 $ (99 ) $ (115 ) Change in Fair Value Recognized in AOCI (11 ) — 1 — (10 ) Amounts Reclassified from AOCI 17 2 — 2 21 Net Current Period Other Comprehensive Income 6 2 1 2 11 Balance in AOCI as of June 30, 2014 $ 6 $ (21 ) $ 8 $ (97 ) $ (104 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and six months ended June 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Generation & Marketing Revenues $ (4 ) $ — Purchased Electricity for Resale 7 (2 ) Subtotal – Commodity 3 (2 ) Interest Rate and Foreign Currency: Interest Expense — 2 Subtotal – Interest Rate and Foreign Currency — 2 Reclassifications from AOCI, before Income Tax (Expense) Credit 3 — Income Tax (Expense) Credit 1 — Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2 — Pension and OPEB Amortization of Prior Service Cost (Credit) (5 ) (5 ) Amortization of Actuarial (Gains)/Losses 6 7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1 2 Income Tax (Expense) Credit — 1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1 1 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 3 $ 1 Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Generation & Marketing Revenues $ (17 ) $ — Purchased Electricity for Resale 6 29 Regulatory Assets/(Liabilities), Net (a) — (3 ) Subtotal – Commodity (11 ) 26 Interest Rate and Foreign Currency: Interest Expense 1 4 Subtotal – Interest Rate and Foreign Currency 1 4 Reclassifications from AOCI, before Income Tax (Expense) Credit (10 ) 30 Income Tax (Expense) Credit (3 ) 11 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (7 ) 19 Pension and OPEB Amortization of Prior Service Cost (Credit) (10 ) (10 ) Amortization of Actuarial (Gains)/Losses 11 14 Reclassifications from AOCI, before Income Tax (Expense) Credit 1 4 Income Tax (Expense) Credit — 2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1 2 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (6 ) $ 21 (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	COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and six months ended June 30, 2015 and 2014 . 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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,025 $ 678 $ 4,703 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 2 (458 ) (456 ) Net Current Period Other Comprehensive Income (Loss) — 2 (458 ) (456 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 87 $ 3,343 $ (566 ) $ 2,864 Change in Fair Value Recognized in AOCI 103 — — 103 Amounts Reclassified from AOCI (190 ) 253 (333 ) (270 ) Net Current Period Other Comprehensive Income (Loss) (87 ) 253 (333 ) (167 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 131 (916 ) (785 ) Net Current Period Other Comprehensive Income (Loss) — 131 (916 ) (785 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 506 (666 ) (1,940 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 506 (666 ) (254 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (14,139 ) $ 58 $ (14,081 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 268 10 278 Net Current Period Other Comprehensive Income — 268 10 278 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 61 $ (15,566 ) $ 464 $ (15,041 ) Change in Fair Value Recognized in AOCI 68 — — 68 Amounts Reclassified from AOCI (129 ) 411 43 325 Net Current Period Other Comprehensive Income (Loss) (61 ) 411 43 393 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 535 22 557 Net Current Period Other Comprehensive Income — 535 22 557 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 821 86 (269 ) Net Current Period Other Comprehensive Income (Loss) (46 ) 821 86 861 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 5,259 $ 5,259 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 6,631 $ 6,631 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (686 ) (686 ) Net Current Period Other Comprehensive Loss — (686 ) (686 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency 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 ) (686 ) (791 ) Net Current Period Other Comprehensive Loss (105 ) (686 ) (791 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,753 $ 4,753 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 5,512 $ 5,512 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (380 ) (380 ) Net Current Period Other Comprehensive Loss — (380 ) (380 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and 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 ) (379 ) (436 ) Net Current Period Other Comprehensive Loss (57 ) (379 ) (436 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (10,469 ) $ 3,330 $ (7,139 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (239 ) 328 Net Current Period Other Comprehensive Income (Loss) — 567 (239 ) 328 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ (12,736 ) $ 4,560 $ (8,176 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,134 (479 ) 655 Net Current Period Other Comprehensive Income (Loss) — 1,134 (479 ) 655 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 ) 1,135 (469 ) 600 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,135 (469 ) 600 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and six months ended June 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (64 ) Regulatory Assets/(Liabilities), Net (a) — (228 ) Subtotal – Commodity — (292 ) Interest Rate and Foreign Currency: Interest Expense 3 390 Subtotal – Interest Rate and Foreign Currency 3 390 Reclassifications from AOCI, before Income Tax (Expense) Credit 3 98 Income Tax (Expense) Credit 1 35 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2 63 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,283 ) (1,283 ) Amortization of Actuarial (Gains)/Losses 578 770 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (513 ) Income Tax (Expense) Credit (247 ) (180 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (456 ) $ (270 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense 202 780 Subtotal – Interest Rate and Foreign Currency 202 780 Reclassifications from AOCI, before Income Tax (Expense) Credit 202 (1,958 ) Income Tax (Expense) Credit 71 (684 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 131 (1,274 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (2,565 ) (2,565 ) Amortization of Actuarial (Gains)/Losses 1,156 1,540 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,409 ) (1,025 ) Income Tax (Expense) Credit (493 ) (359 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (916 ) (666 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (785 ) $ (1,940 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (95 ) Regulatory Assets/(Liabilities), Net (a) — (103 ) Subtotal – Commodity — (198 ) Interest Rate and Foreign Currency: Interest Expense 411 631 Subtotal – Interest Rate and Foreign Currency 411 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 411 433 Income Tax (Expense) Credit 143 151 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 268 282 Pension and OPEB Amortization of Prior Service Cost (Credit) (199 ) (198 ) Amortization of Actuarial (Gains)/Losses 215 262 Reclassifications from AOCI, before Income Tax (Expense) Credit 16 64 Income Tax (Expense) Credit 6 21 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10 43 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 325 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 822 1,262 Subtotal – Interest Rate and Foreign Currency 822 1,262 Reclassifications from AOCI, before Income Tax (Expense) Credit 822 (547 ) Income Tax (Expense) Credit 287 (192 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 535 (355 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (398 ) (397 ) Amortization of Actuarial (Gains)/Losses 432 527 Reclassifications from AOCI, before Income Tax (Expense) Credit 34 130 Income Tax (Expense) Credit 12 44 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 22 86 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 557 $ (269 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (3 ) (3 ) Interest Expense (524 ) (524 ) Subtotal – Interest Rate and Foreign Currency (527 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (527 ) (527 ) Income Tax (Expense) Credit (184 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (343 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (6 ) (6 ) Interest Expense (1,048 ) (1,048 ) Subtotal – Interest Rate and Foreign Currency (1,054 ) (1,054 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,054 ) (1,216 ) Income Tax (Expense) Credit (368 ) (425 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (686 ) $ (791 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 (292 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (190 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (584 ) (584 ) Subtotal – Interest Rate and Foreign Currency (584 ) (584 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (584 ) (672 ) Income Tax (Expense) Credit (204 ) (236 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (380 ) $ (436 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 872 872 Income Tax (Expense) Credit 305 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 567 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (467 ) (477 ) Amortization of Actuarial (Gains)/Losses 99 115 Reclassifications from AOCI, before Income Tax (Expense) Credit (368 ) (362 ) Income Tax (Expense) Credit (129 ) (127 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (239 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 328 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 1,744 1,744 Subtotal – Interest Rate and Foreign Currency 1,744 1,744 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,744 1,643 Income Tax (Expense) Credit 610 574 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,134 1,069 Pension and OPEB Amortization of Prior Service Cost (Credit) (934 ) (955 ) Amortization of Actuarial (Gains)/Losses 197 233 Reclassifications from AOCI, before Income Tax (Expense) Credit (737 ) (722 ) Income Tax (Expense) Credit (258 ) (253 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (479 ) (469 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 655 $ 600 (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	COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and six months ended June 30, 2015 and 2014 . 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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,025 $ 678 $ 4,703 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 2 (458 ) (456 ) Net Current Period Other Comprehensive Income (Loss) — 2 (458 ) (456 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 87 $ 3,343 $ (566 ) $ 2,864 Change in Fair Value Recognized in AOCI 103 — — 103 Amounts Reclassified from AOCI (190 ) 253 (333 ) (270 ) Net Current Period Other Comprehensive Income (Loss) (87 ) 253 (333 ) (167 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 131 (916 ) (785 ) Net Current Period Other Comprehensive Income (Loss) — 131 (916 ) (785 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 506 (666 ) (1,940 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 506 (666 ) (254 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (14,139 ) $ 58 $ (14,081 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 268 10 278 Net Current Period Other Comprehensive Income — 268 10 278 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 61 $ (15,566 ) $ 464 $ (15,041 ) Change in Fair Value Recognized in AOCI 68 — — 68 Amounts Reclassified from AOCI (129 ) 411 43 325 Net Current Period Other Comprehensive Income (Loss) (61 ) 411 43 393 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 535 22 557 Net Current Period Other Comprehensive Income — 535 22 557 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 821 86 (269 ) Net Current Period Other Comprehensive Income (Loss) (46 ) 821 86 861 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 5,259 $ 5,259 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 6,631 $ 6,631 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (686 ) (686 ) Net Current Period Other Comprehensive Loss — (686 ) (686 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency 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 ) (686 ) (791 ) Net Current Period Other Comprehensive Loss (105 ) (686 ) (791 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,753 $ 4,753 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 5,512 $ 5,512 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (380 ) (380 ) Net Current Period Other Comprehensive Loss — (380 ) (380 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and 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 ) (379 ) (436 ) Net Current Period Other Comprehensive Loss (57 ) (379 ) (436 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (10,469 ) $ 3,330 $ (7,139 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (239 ) 328 Net Current Period Other Comprehensive Income (Loss) — 567 (239 ) 328 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ (12,736 ) $ 4,560 $ (8,176 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,134 (479 ) 655 Net Current Period Other Comprehensive Income (Loss) — 1,134 (479 ) 655 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 ) 1,135 (469 ) 600 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,135 (469 ) 600 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and six months ended June 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (64 ) Regulatory Assets/(Liabilities), Net (a) — (228 ) Subtotal – Commodity — (292 ) Interest Rate and Foreign Currency: Interest Expense 3 390 Subtotal – Interest Rate and Foreign Currency 3 390 Reclassifications from AOCI, before Income Tax (Expense) Credit 3 98 Income Tax (Expense) Credit 1 35 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2 63 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,283 ) (1,283 ) Amortization of Actuarial (Gains)/Losses 578 770 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (513 ) Income Tax (Expense) Credit (247 ) (180 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (456 ) $ (270 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense 202 780 Subtotal – Interest Rate and Foreign Currency 202 780 Reclassifications from AOCI, before Income Tax (Expense) Credit 202 (1,958 ) Income Tax (Expense) Credit 71 (684 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 131 (1,274 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (2,565 ) (2,565 ) Amortization of Actuarial (Gains)/Losses 1,156 1,540 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,409 ) (1,025 ) Income Tax (Expense) Credit (493 ) (359 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (916 ) (666 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (785 ) $ (1,940 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (95 ) Regulatory Assets/(Liabilities), Net (a) — (103 ) Subtotal – Commodity — (198 ) Interest Rate and Foreign Currency: Interest Expense 411 631 Subtotal – Interest Rate and Foreign Currency 411 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 411 433 Income Tax (Expense) Credit 143 151 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 268 282 Pension and OPEB Amortization of Prior Service Cost (Credit) (199 ) (198 ) Amortization of Actuarial (Gains)/Losses 215 262 Reclassifications from AOCI, before Income Tax (Expense) Credit 16 64 Income Tax (Expense) Credit 6 21 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10 43 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 325 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 822 1,262 Subtotal – Interest Rate and Foreign Currency 822 1,262 Reclassifications from AOCI, before Income Tax (Expense) Credit 822 (547 ) Income Tax (Expense) Credit 287 (192 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 535 (355 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (398 ) (397 ) Amortization of Actuarial (Gains)/Losses 432 527 Reclassifications from AOCI, before Income Tax (Expense) Credit 34 130 Income Tax (Expense) Credit 12 44 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 22 86 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 557 $ (269 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (3 ) (3 ) Interest Expense (524 ) (524 ) Subtotal – Interest Rate and Foreign Currency (527 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (527 ) (527 ) Income Tax (Expense) Credit (184 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (343 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (6 ) (6 ) Interest Expense (1,048 ) (1,048 ) Subtotal – Interest Rate and Foreign Currency (1,054 ) (1,054 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,054 ) (1,216 ) Income Tax (Expense) Credit (368 ) (425 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (686 ) $ (791 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 (292 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (190 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (584 ) (584 ) Subtotal – Interest Rate and Foreign Currency (584 ) (584 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (584 ) (672 ) Income Tax (Expense) Credit (204 ) (236 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (380 ) $ (436 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 872 872 Income Tax (Expense) Credit 305 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 567 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (467 ) (477 ) Amortization of Actuarial (Gains)/Losses 99 115 Reclassifications from AOCI, before Income Tax (Expense) Credit (368 ) (362 ) Income Tax (Expense) Credit (129 ) (127 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (239 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 328 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 1,744 1,744 Subtotal – Interest Rate and Foreign Currency 1,744 1,744 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,744 1,643 Income Tax (Expense) Credit 610 574 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,134 1,069 Pension and OPEB Amortization of Prior Service Cost (Credit) (934 ) (955 ) Amortization of Actuarial (Gains)/Losses 197 233 Reclassifications from AOCI, before Income Tax (Expense) Credit (737 ) (722 ) Income Tax (Expense) Credit (258 ) (253 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (479 ) (469 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 655 $ 600 (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	COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and six months ended June 30, 2015 and 2014 . 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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,025 $ 678 $ 4,703 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 2 (458 ) (456 ) Net Current Period Other Comprehensive Income (Loss) — 2 (458 ) (456 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 87 $ 3,343 $ (566 ) $ 2,864 Change in Fair Value Recognized in AOCI 103 — — 103 Amounts Reclassified from AOCI (190 ) 253 (333 ) (270 ) Net Current Period Other Comprehensive Income (Loss) (87 ) 253 (333 ) (167 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 131 (916 ) (785 ) Net Current Period Other Comprehensive Income (Loss) — 131 (916 ) (785 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 506 (666 ) (1,940 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 506 (666 ) (254 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (14,139 ) $ 58 $ (14,081 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 268 10 278 Net Current Period Other Comprehensive Income — 268 10 278 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 61 $ (15,566 ) $ 464 $ (15,041 ) Change in Fair Value Recognized in AOCI 68 — — 68 Amounts Reclassified from AOCI (129 ) 411 43 325 Net Current Period Other Comprehensive Income (Loss) (61 ) 411 43 393 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 535 22 557 Net Current Period Other Comprehensive Income — 535 22 557 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 821 86 (269 ) Net Current Period Other Comprehensive Income (Loss) (46 ) 821 86 861 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 5,259 $ 5,259 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 6,631 $ 6,631 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (686 ) (686 ) Net Current Period Other Comprehensive Loss — (686 ) (686 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency 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 ) (686 ) (791 ) Net Current Period Other Comprehensive Loss (105 ) (686 ) (791 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,753 $ 4,753 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 5,512 $ 5,512 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (380 ) (380 ) Net Current Period Other Comprehensive Loss — (380 ) (380 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and 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 ) (379 ) (436 ) Net Current Period Other Comprehensive Loss (57 ) (379 ) (436 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (10,469 ) $ 3,330 $ (7,139 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (239 ) 328 Net Current Period Other Comprehensive Income (Loss) — 567 (239 ) 328 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ (12,736 ) $ 4,560 $ (8,176 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,134 (479 ) 655 Net Current Period Other Comprehensive Income (Loss) — 1,134 (479 ) 655 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 ) 1,135 (469 ) 600 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,135 (469 ) 600 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and six months ended June 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (64 ) Regulatory Assets/(Liabilities), Net (a) — (228 ) Subtotal – Commodity — (292 ) Interest Rate and Foreign Currency: Interest Expense 3 390 Subtotal – Interest Rate and Foreign Currency 3 390 Reclassifications from AOCI, before Income Tax (Expense) Credit 3 98 Income Tax (Expense) Credit 1 35 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2 63 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,283 ) (1,283 ) Amortization of Actuarial (Gains)/Losses 578 770 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (513 ) Income Tax (Expense) Credit (247 ) (180 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (456 ) $ (270 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense 202 780 Subtotal – Interest Rate and Foreign Currency 202 780 Reclassifications from AOCI, before Income Tax (Expense) Credit 202 (1,958 ) Income Tax (Expense) Credit 71 (684 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 131 (1,274 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (2,565 ) (2,565 ) Amortization of Actuarial (Gains)/Losses 1,156 1,540 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,409 ) (1,025 ) Income Tax (Expense) Credit (493 ) (359 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (916 ) (666 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (785 ) $ (1,940 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (95 ) Regulatory Assets/(Liabilities), Net (a) — (103 ) Subtotal – Commodity — (198 ) Interest Rate and Foreign Currency: Interest Expense 411 631 Subtotal – Interest Rate and Foreign Currency 411 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 411 433 Income Tax (Expense) Credit 143 151 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 268 282 Pension and OPEB Amortization of Prior Service Cost (Credit) (199 ) (198 ) Amortization of Actuarial (Gains)/Losses 215 262 Reclassifications from AOCI, before Income Tax (Expense) Credit 16 64 Income Tax (Expense) Credit 6 21 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10 43 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 325 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 822 1,262 Subtotal – Interest Rate and Foreign Currency 822 1,262 Reclassifications from AOCI, before Income Tax (Expense) Credit 822 (547 ) Income Tax (Expense) Credit 287 (192 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 535 (355 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (398 ) (397 ) Amortization of Actuarial (Gains)/Losses 432 527 Reclassifications from AOCI, before Income Tax (Expense) Credit 34 130 Income Tax (Expense) Credit 12 44 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 22 86 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 557 $ (269 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (3 ) (3 ) Interest Expense (524 ) (524 ) Subtotal – Interest Rate and Foreign Currency (527 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (527 ) (527 ) Income Tax (Expense) Credit (184 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (343 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (6 ) (6 ) Interest Expense (1,048 ) (1,048 ) Subtotal – Interest Rate and Foreign Currency (1,054 ) (1,054 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,054 ) (1,216 ) Income Tax (Expense) Credit (368 ) (425 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (686 ) $ (791 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 (292 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (190 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (584 ) (584 ) Subtotal – Interest Rate and Foreign Currency (584 ) (584 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (584 ) (672 ) Income Tax (Expense) Credit (204 ) (236 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (380 ) $ (436 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 872 872 Income Tax (Expense) Credit 305 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 567 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (467 ) (477 ) Amortization of Actuarial (Gains)/Losses 99 115 Reclassifications from AOCI, before Income Tax (Expense) Credit (368 ) (362 ) Income Tax (Expense) Credit (129 ) (127 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (239 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 328 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 1,744 1,744 Subtotal – Interest Rate and Foreign Currency 1,744 1,744 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,744 1,643 Income Tax (Expense) Credit 610 574 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,134 1,069 Pension and OPEB Amortization of Prior Service Cost (Credit) (934 ) (955 ) Amortization of Actuarial (Gains)/Losses 197 233 Reclassifications from AOCI, before Income Tax (Expense) Credit (737 ) (722 ) Income Tax (Expense) Credit (258 ) (253 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (479 ) (469 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 655 $ 600 (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	COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and six months ended June 30, 2015 and 2014 . 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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,025 $ 678 $ 4,703 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 2 (458 ) (456 ) Net Current Period Other Comprehensive Income (Loss) — 2 (458 ) (456 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 87 $ 3,343 $ (566 ) $ 2,864 Change in Fair Value Recognized in AOCI 103 — — 103 Amounts Reclassified from AOCI (190 ) 253 (333 ) (270 ) Net Current Period Other Comprehensive Income (Loss) (87 ) 253 (333 ) (167 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 131 (916 ) (785 ) Net Current Period Other Comprehensive Income (Loss) — 131 (916 ) (785 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 506 (666 ) (1,940 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 506 (666 ) (254 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (14,139 ) $ 58 $ (14,081 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 268 10 278 Net Current Period Other Comprehensive Income — 268 10 278 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 61 $ (15,566 ) $ 464 $ (15,041 ) Change in Fair Value Recognized in AOCI 68 — — 68 Amounts Reclassified from AOCI (129 ) 411 43 325 Net Current Period Other Comprehensive Income (Loss) (61 ) 411 43 393 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 535 22 557 Net Current Period Other Comprehensive Income — 535 22 557 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 821 86 (269 ) Net Current Period Other Comprehensive Income (Loss) (46 ) 821 86 861 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 5,259 $ 5,259 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 6,631 $ 6,631 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (686 ) (686 ) Net Current Period Other Comprehensive Loss — (686 ) (686 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency 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 ) (686 ) (791 ) Net Current Period Other Comprehensive Loss (105 ) (686 ) (791 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,753 $ 4,753 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 5,512 $ 5,512 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (380 ) (380 ) Net Current Period Other Comprehensive Loss — (380 ) (380 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and 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 ) (379 ) (436 ) Net Current Period Other Comprehensive Loss (57 ) (379 ) (436 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (10,469 ) $ 3,330 $ (7,139 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (239 ) 328 Net Current Period Other Comprehensive Income (Loss) — 567 (239 ) 328 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ (12,736 ) $ 4,560 $ (8,176 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,134 (479 ) 655 Net Current Period Other Comprehensive Income (Loss) — 1,134 (479 ) 655 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 ) 1,135 (469 ) 600 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,135 (469 ) 600 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and six months ended June 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (64 ) Regulatory Assets/(Liabilities), Net (a) — (228 ) Subtotal – Commodity — (292 ) Interest Rate and Foreign Currency: Interest Expense 3 390 Subtotal – Interest Rate and Foreign Currency 3 390 Reclassifications from AOCI, before Income Tax (Expense) Credit 3 98 Income Tax (Expense) Credit 1 35 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2 63 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,283 ) (1,283 ) Amortization of Actuarial (Gains)/Losses 578 770 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (513 ) Income Tax (Expense) Credit (247 ) (180 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (456 ) $ (270 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense 202 780 Subtotal – Interest Rate and Foreign Currency 202 780 Reclassifications from AOCI, before Income Tax (Expense) Credit 202 (1,958 ) Income Tax (Expense) Credit 71 (684 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 131 (1,274 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (2,565 ) (2,565 ) Amortization of Actuarial (Gains)/Losses 1,156 1,540 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,409 ) (1,025 ) Income Tax (Expense) Credit (493 ) (359 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (916 ) (666 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (785 ) $ (1,940 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (95 ) Regulatory Assets/(Liabilities), Net (a) — (103 ) Subtotal – Commodity — (198 ) Interest Rate and Foreign Currency: Interest Expense 411 631 Subtotal – Interest Rate and Foreign Currency 411 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 411 433 Income Tax (Expense) Credit 143 151 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 268 282 Pension and OPEB Amortization of Prior Service Cost (Credit) (199 ) (198 ) Amortization of Actuarial (Gains)/Losses 215 262 Reclassifications from AOCI, before Income Tax (Expense) Credit 16 64 Income Tax (Expense) Credit 6 21 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10 43 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 325 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 822 1,262 Subtotal – Interest Rate and Foreign Currency 822 1,262 Reclassifications from AOCI, before Income Tax (Expense) Credit 822 (547 ) Income Tax (Expense) Credit 287 (192 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 535 (355 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (398 ) (397 ) Amortization of Actuarial (Gains)/Losses 432 527 Reclassifications from AOCI, before Income Tax (Expense) Credit 34 130 Income Tax (Expense) Credit 12 44 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 22 86 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 557 $ (269 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (3 ) (3 ) Interest Expense (524 ) (524 ) Subtotal – Interest Rate and Foreign Currency (527 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (527 ) (527 ) Income Tax (Expense) Credit (184 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (343 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (6 ) (6 ) Interest Expense (1,048 ) (1,048 ) Subtotal – Interest Rate and Foreign Currency (1,054 ) (1,054 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,054 ) (1,216 ) Income Tax (Expense) Credit (368 ) (425 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (686 ) $ (791 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 (292 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (190 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (584 ) (584 ) Subtotal – Interest Rate and Foreign Currency (584 ) (584 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (584 ) (672 ) Income Tax (Expense) Credit (204 ) (236 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (380 ) $ (436 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 872 872 Income Tax (Expense) Credit 305 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 567 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (467 ) (477 ) Amortization of Actuarial (Gains)/Losses 99 115 Reclassifications from AOCI, before Income Tax (Expense) Credit (368 ) (362 ) Income Tax (Expense) Credit (129 ) (127 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (239 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 328 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 1,744 1,744 Subtotal – Interest Rate and Foreign Currency 1,744 1,744 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,744 1,643 Income Tax (Expense) Credit 610 574 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,134 1,069 Pension and OPEB Amortization of Prior Service Cost (Credit) (934 ) (955 ) Amortization of Actuarial (Gains)/Losses 197 233 Reclassifications from AOCI, before Income Tax (Expense) Credit (737 ) (722 ) Income Tax (Expense) Credit (258 ) (253 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (479 ) (469 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 655 $ 600 (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	COMPREHENSIVE INCOME Presentation of Comprehensive Income The following tables provide the components of changes in AOCI for the three and six months ended June 30, 2015 and 2014 . 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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,025 $ 678 $ 4,703 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 2 (458 ) (456 ) Net Current Period Other Comprehensive Income (Loss) — 2 (458 ) (456 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 87 $ 3,343 $ (566 ) $ 2,864 Change in Fair Value Recognized in AOCI 103 — — 103 Amounts Reclassified from AOCI (190 ) 253 (333 ) (270 ) Net Current Period Other Comprehensive Income (Loss) (87 ) 253 (333 ) (167 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 131 (916 ) (785 ) Net Current Period Other Comprehensive Income (Loss) — 131 (916 ) (785 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 506 (666 ) (1,940 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 506 (666 ) (254 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (14,139 ) $ 58 $ (14,081 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 268 10 278 Net Current Period Other Comprehensive Income — 268 10 278 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 61 $ (15,566 ) $ 464 $ (15,041 ) Change in Fair Value Recognized in AOCI 68 — — 68 Amounts Reclassified from AOCI (129 ) 411 43 325 Net Current Period Other Comprehensive Income (Loss) (61 ) 411 43 393 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 535 22 557 Net Current Period Other Comprehensive Income — 535 22 557 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 821 86 (269 ) Net Current Period Other Comprehensive Income (Loss) (46 ) 821 86 861 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 5,259 $ 5,259 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 6,631 $ 6,631 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (686 ) (686 ) Net Current Period Other Comprehensive Loss — (686 ) (686 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency 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 ) (686 ) (791 ) Net Current Period Other Comprehensive Loss (105 ) (686 ) (791 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,753 $ 4,753 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 5,512 $ 5,512 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (380 ) (380 ) Net Current Period Other Comprehensive Loss — (380 ) (380 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and 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 ) (379 ) (436 ) Net Current Period Other Comprehensive Loss (57 ) (379 ) (436 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (10,469 ) $ 3,330 $ (7,139 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (239 ) 328 Net Current Period Other Comprehensive Income (Loss) — 567 (239 ) 328 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ (12,736 ) $ 4,560 $ (8,176 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,134 (479 ) 655 Net Current Period Other Comprehensive Income (Loss) — 1,134 (479 ) 655 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 ) 1,135 (469 ) 600 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,135 (469 ) 600 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) Reclassifications from Accumulated Other Comprehensive Income The following tables provide details of reclassifications from AOCI for the three and six months ended June 30, 2015 and 2014 . The amortization of pension and OPEB AOCI components are included in the computation of net periodic pension and OPEB costs. See Note 6 for additional details. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (64 ) Regulatory Assets/(Liabilities), Net (a) — (228 ) Subtotal – Commodity — (292 ) Interest Rate and Foreign Currency: Interest Expense 3 390 Subtotal – Interest Rate and Foreign Currency 3 390 Reclassifications from AOCI, before Income Tax (Expense) Credit 3 98 Income Tax (Expense) Credit 1 35 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2 63 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,283 ) (1,283 ) Amortization of Actuarial (Gains)/Losses 578 770 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (513 ) Income Tax (Expense) Credit (247 ) (180 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (456 ) $ (270 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense 202 780 Subtotal – Interest Rate and Foreign Currency 202 780 Reclassifications from AOCI, before Income Tax (Expense) Credit 202 (1,958 ) Income Tax (Expense) Credit 71 (684 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 131 (1,274 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (2,565 ) (2,565 ) Amortization of Actuarial (Gains)/Losses 1,156 1,540 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,409 ) (1,025 ) Income Tax (Expense) Credit (493 ) (359 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (916 ) (666 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (785 ) $ (1,940 ) I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (95 ) Regulatory Assets/(Liabilities), Net (a) — (103 ) Subtotal – Commodity — (198 ) Interest Rate and Foreign Currency: Interest Expense 411 631 Subtotal – Interest Rate and Foreign Currency 411 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 411 433 Income Tax (Expense) Credit 143 151 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 268 282 Pension and OPEB Amortization of Prior Service Cost (Credit) (199 ) (198 ) Amortization of Actuarial (Gains)/Losses 215 262 Reclassifications from AOCI, before Income Tax (Expense) Credit 16 64 Income Tax (Expense) Credit 6 21 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10 43 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 325 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 822 1,262 Subtotal – Interest Rate and Foreign Currency 822 1,262 Reclassifications from AOCI, before Income Tax (Expense) Credit 822 (547 ) Income Tax (Expense) Credit 287 (192 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 535 (355 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (398 ) (397 ) Amortization of Actuarial (Gains)/Losses 432 527 Reclassifications from AOCI, before Income Tax (Expense) Credit 34 130 Income Tax (Expense) Credit 12 44 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 22 86 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 557 $ (269 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (3 ) (3 ) Interest Expense (524 ) (524 ) Subtotal – Interest Rate and Foreign Currency (527 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (527 ) (527 ) Income Tax (Expense) Credit (184 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (343 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (6 ) (6 ) Interest Expense (1,048 ) (1,048 ) Subtotal – Interest Rate and Foreign Currency (1,054 ) (1,054 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,054 ) (1,216 ) Income Tax (Expense) Credit (368 ) (425 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (686 ) $ (791 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 (292 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (190 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (584 ) (584 ) Subtotal – Interest Rate and Foreign Currency (584 ) (584 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (584 ) (672 ) Income Tax (Expense) Credit (204 ) (236 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (380 ) $ (436 ) SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 872 872 Income Tax (Expense) Credit 305 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 567 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (467 ) (477 ) Amortization of Actuarial (Gains)/Losses 99 115 Reclassifications from AOCI, before Income Tax (Expense) Credit (368 ) (362 ) Income Tax (Expense) Credit (129 ) (127 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (239 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 328 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 1,744 1,744 Subtotal – Interest Rate and Foreign Currency 1,744 1,744 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,744 1,643 Income Tax (Expense) Credit 610 574 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,134 1,069 Pension and OPEB Amortization of Prior Service Cost (Credit) (934 ) (955 ) Amortization of Actuarial (Gains)/Losses 197 233 Reclassifications from AOCI, before Income Tax (Expense) Credit (737 ) (722 ) Income Tax (Expense) Credit (258 ) (253 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (479 ) (469 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 655 $ 600 (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	6 Months Ended
	Jun. 30, 2015
Rate Matters	RATE MATTERS As discussed in the 2014 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. The Rate Matters note within our 2014 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 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Storm Related Costs $ 20 $ 20 Material and Supplies Related to Retired Plants 19 — West Virginia Vegetation Management Program — 20 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 51 — Virginia Demand Response Program Costs 11 9 Ormet Special Rate Recovery Mechanism 10 10 Storm Related Costs 3 100 Carbon Capture and Storage Product Validation Facility — 13 IGCC Pre-Construction Costs — 11 Other Regulatory Assets Pending Final Regulatory Approval 23 43 Total Regulatory Assets Pending Final Regulatory Approval $ 137 $ 226 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. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. If the Supreme Court of Ohio upholds its June 2015 order, it would remand the matter back to the PUCO for reinstatement of the WACC rate. Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the ruling in this proceeding, it could impact future net income, cash flows and financial condition. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In July 2014, OPCo submitted a separate application to continue the RSR to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00 /MWh, until the balance of the capacity deferrals has been collected. In April 2015, the PUCO issued an order approving the application to continue the RSR, with modifications. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of June 30, 2015 , OPCo's incurred deferred capacity costs balance of $432 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. As provided for in the June 2015 - May 2018 ESP, for delivery starting in June 2015, OPCo now conducts energy and capacity auctions for its entire SSO load. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal included a return on common equity of 10.65% on capital costs for certain riders. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, on rehearing, the PUCO issued an order that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In June 2015, OPCo and various intervenors filed applications for rehearing with the PUCO related to the May 2015 order on rehearing. In July 2015, the PUCO granted the requests for rehearing. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) continued to include the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo filed its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation 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. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of June 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. 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 was held in 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. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of June 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 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 and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery 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 review base rates in 2014 and 2015 and that SWEPCo 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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, which was 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. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which will be effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million , excluding AFUDC. As of June 30, 2015 , SWEPCo has incurred costs of $256 million , including AFUDC, and has remaining contractual construction obligations of $89 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of June 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $484 million , before cost of removal, including materials and supplies inventory and CWIP. 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 2014 West Virginia Base Rate Case In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $181 million , based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested recovery of $89 million in regulatory assets over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $45 million annually to recover vegetation management costs, including a return on capital investment. In May 2015, the WVPSC issued an order on the base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $99 million based upon a 9.75% return on common equity. The order included a delayed billing of $25 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $25 million annual delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $45 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $89 million in previously recorded regulatory assets, which will predominantly be recovered over five years. In June 2015, the WVPSC staff and intervenors filed motions for reconsideration and clarification related to various issues including recovery of lost revenues and the allowed carrying charge rate related to the delayed residential revenues. In July 2015, the WVPSC issued an order that denied all motions for reconsideration. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. As of June 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding are estimated to be $12 million . In February and March 2015, briefs related to this proceeding were filed by various parties. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 for Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on equity of 10.5% and is proposed to be effective in January 2016, except for the $44 million for environmental investments, which is proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of June 30, 2015 , PSO has incurred costs of $140 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that future incremental purchased capacity and energy costs of an estimated $35 million will be incurred related to the environmental compliance plan, due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of June 30, 2015 , the net book value of Northeastern Plant, Unit 4 was $95 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies. These additional regulatory assets are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million , excluding AFUDC, would be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider would allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M would defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M did not seek a rate adjustment in this proceeding but sought approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. In April 2015, I&M filed a notice with the IURC to seek approval of the proposed TDSIC Plan excluding $117 million of certain projects that were challenged in this proceeding. In May 2015, the IURC issued an order that denied I&M's TDSIC Plan and Rider. In May 2015, I&M filed a petition for reconsideration and/or rehearing with the IURC and in June 2015, filed a notice of appeal with the Indiana Court of Appeals. KPCo Rate Matters Plant Transfer In October 2013, the KPSC issued an order that approved a modified settlement agreement which included the approval to transfer to KPCo a one-half interest in the Mitchell Plant, comprising 780 MW of average annual generating capacity. In December 2013, the transfer of a one-half interest in the Mitchell Plant to KPCo was completed. In December 2013, the Attorney General filed an appeal of the order with the Franklin County Circuit Court. In April 2015, the Franklin County Circuit Court issued an order that affirmed the KPSC's October 2013 order. In May 2015, the Attorney General filed an appeal of the April 2015 Franklin County Circuit Court order that had affirmed the KPSC's order. Consistent with KPCo’s December 2012 plant transfer filing with the KPSC, Big Sandy Plant, Unit 2 was retired in May 2015. Upon retirement, $194 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Big Sandy Plant, Unit 2 and the related asset retirement obligations, costs of removal and materials and supplies. These regulatory assets will be amortized over 25 years, effective July 2015. Kentucky Fuel Adjustment Clause Review In August 2014, the KPSC issued an order initiating a review of KPCo's FAC from November 2013 through April 2014. In January 2015, the KPSC issued an order disallowing certain FAC costs during the period of January 2014 through May 2015 while KPCo owned and operated both Big Sandy Plant, Unit 2 and its one-half interest in the Mitchell Plant. As a result of this order, KPCo recorded a regulatory disallowance of $36 million in December 2014. In February 2015, KPCo filed an appeal of this order with the Franklin County Circuit Court. In April 2015, the Franklin County Circuit Court issued an order approving intervenors' requests to hold this case in abeyance until the KPSC issues a final order in KPCo’s two-year FAC review case for the period November 2012 through October 2014. 2014 Kentucky Base Rate Case In December 2014, KPCo filed a request with the KPSC for a net increase in rates o
Appalachian Power Co [Member]
Rate Matters	RATE MATTERS As discussed in the 2014 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 2014 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 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115 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. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. If the Supreme Court of Ohio upholds its June 2015 order, it would remand the matter back to the PUCO for reinstatement of the WACC rate. Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the ruling in this proceeding, it could impact future net income, cash flows and financial condition. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In July 2014, OPCo submitted a separate application to continue the RSR to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00 /MWh until the balance of the capacity deferrals has been collected. In April 2015, the PUCO issued an order approving the application to continue the RSR, with modifications. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of June 30, 2015 , OPCo's incurred deferred capacity costs balance of $432 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. As provided for in the June 2015 - May 2018 ESP, for delivery starting in June 2015, OPCo now conducts energy and capacity auctions for its entire SSO load. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal included a return on common equity of 10.65% on capital costs for certain riders. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, on rehearing, the PUCO issued an order that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In June 2015, OPCo and various intervenors filed applications for rehearing with the PUCO related to the May 2015 order on rehearing. In July 2015, the PUCO granted the requests for rehearing. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) continued to include the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo filed its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation 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. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of June 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. 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 was held in 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. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of June 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 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 and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery 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 review base rates in 2014 and 2015 and that SWEPCo 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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, which was 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. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which will be effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million , excluding AFUDC. As of June 30, 2015 , SWEPCo has incurred costs of $256 million , including AFUDC, and has remaining contractual construction obligations of $89 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of June 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $484 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million , based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested recovery of $77 million in regulatory assets over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover vegetation management costs, including a return on capital investment. In May 2015, the WVPSC issued an order on the base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million annual delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. In June 2015, the WVPSC staff and intervenors filed motions for reconsideration and clarification related to various issues including recovery of lost revenues and the allowed carrying charge rate related to the delayed residential revenues. In July 2015, the WVPSC issued an order that denied all motions for reconsideration. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. As of June 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding are estimated to be $12 million . In February and March 2015, briefs related to this proceeding were filed by various parties. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 for Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on equity of 10.5% and is proposed to be effective in January 2016, except for the $44 million for environmental investments, which is proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of June 30, 2015, PSO has incurred costs of $140 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that future incremental purchased capacity and energy costs of an estimated $35 million will be incurred related to the environmental compliance plan, due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of June 30, 2015, the net book value of Northeastern Plant, Unit 4 was $95 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies. These additional regulatory assets are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million , excluding AFUDC, would be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider would allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M would defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M did not seek a rate adjustment in this proceeding but sought approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. In April 2015, I&M filed a notice with the IURC to seek approval of the proposed TDSIC Plan excluding $117 million of certain projects that were challenged in this proceeding. In May 2015, the IURC issued an order that denied I&M's TDSIC Plan and Rider. In May 2015, I&M filed a petition for reconsideration and/or rehearing with the IURC and in June 2015, filed a notice of appeal with the Indiana Court of Appeals.
Indiana Michigan Power Co [Member]
Rate Matters	RATE MATTERS As discussed in the 2014 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 2014 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 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115 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. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. If the Supreme Court of Ohio upholds its June 2015 order, it would remand the matter back to the PUCO for reinstatement of the WACC rate. Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the ruling in this proceeding, it could impact future net income, cash flows and financial condition. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In July 2014, OPCo submitted a separate application to continue the RSR to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00 /MWh until the balance of the capacity deferrals has been collected. In April 2015, the PUCO issued an order approving the application to continue the RSR, with modifications. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of June 30, 2015 , OPCo's incurred deferred capacity costs balance of $432 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. As provided for in the June 2015 - May 2018 ESP, for delivery starting in June 2015, OPCo now conducts energy and capacity auctions for its entire SSO load. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal included a return on common equity of 10.65% on capital costs for certain riders. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, on rehearing, the PUCO issued an order that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In June 2015, OPCo and various intervenors filed applications for rehearing with the PUCO related to the May 2015 order on rehearing. In July 2015, the PUCO granted the requests for rehearing. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) continued to include the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo filed its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation 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. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of June 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. 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 was held in 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. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of June 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 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 and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery 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 review base rates in 2014 and 2015 and that SWEPCo 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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, which was 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. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which will be effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million , excluding AFUDC. As of June 30, 2015 , SWEPCo has incurred costs of $256 million , including AFUDC, and has remaining contractual construction obligations of $89 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of June 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $484 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million , based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested recovery of $77 million in regulatory assets over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover vegetation management costs, including a return on capital investment. In May 2015, the WVPSC issued an order on the base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million annual delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. In June 2015, the WVPSC staff and intervenors filed motions for reconsideration and clarification related to various issues including recovery of lost revenues and the allowed carrying charge rate related to the delayed residential revenues. In July 2015, the WVPSC issued an order that denied all motions for reconsideration. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. As of June 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding are estimated to be $12 million . In February and March 2015, briefs related to this proceeding were filed by various parties. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 for Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on equity of 10.5% and is proposed to be effective in January 2016, except for the $44 million for environmental investments, which is proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of June 30, 2015, PSO has incurred costs of $140 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that future incremental purchased capacity and energy costs of an estimated $35 million will be incurred related to the environmental compliance plan, due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of June 30, 2015, the net book value of Northeastern Plant, Unit 4 was $95 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies. These additional regulatory assets are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million , excluding AFUDC, would be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider would allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M would defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M did not seek a rate adjustment in this proceeding but sought approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. In April 2015, I&M filed a notice with the IURC to seek approval of the proposed TDSIC Plan excluding $117 million of certain projects that were challenged in this proceeding. In May 2015, the IURC issued an order that denied I&M's TDSIC Plan and Rider. In May 2015, I&M filed a petition for reconsideration and/or rehearing with the IURC and in June 2015, filed a notice of appeal with the Indiana Court of Appeals.
Ohio Power Co [Member]
Rate Matters	RATE MATTERS As discussed in the 2014 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 2014 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 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115 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. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. If the Supreme Court of Ohio upholds its June 2015 order, it would remand the matter back to the PUCO for reinstatement of the WACC rate. Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the ruling in this proceeding, it could impact future net income, cash flows and financial condition. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In July 2014, OPCo submitted a separate application to continue the RSR to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00 /MWh until the balance of the capacity deferrals has been collected. In April 2015, the PUCO issued an order approving the application to continue the RSR, with modifications. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of June 30, 2015 , OPCo's incurred deferred capacity costs balance of $432 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. As provided for in the June 2015 - May 2018 ESP, for delivery starting in June 2015, OPCo now conducts energy and capacity auctions for its entire SSO load. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal included a return on common equity of 10.65% on capital costs for certain riders. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, on rehearing, the PUCO issued an order that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In June 2015, OPCo and various intervenors filed applications for rehearing with the PUCO related to the May 2015 order on rehearing. In July 2015, the PUCO granted the requests for rehearing. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) continued to include the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo filed its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation 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. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of June 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. 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 was held in 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. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of June 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 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 and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery 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 review base rates in 2014 and 2015 and that SWEPCo 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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, which was 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. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which will be effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million , excluding AFUDC. As of June 30, 2015 , SWEPCo has incurred costs of $256 million , including AFUDC, and has remaining contractual construction obligations of $89 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of June 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $484 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million , based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested recovery of $77 million in regulatory assets over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover vegetation management costs, including a return on capital investment. In May 2015, the WVPSC issued an order on the base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million annual delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. In June 2015, the WVPSC staff and intervenors filed motions for reconsideration and clarification related to various issues including recovery of lost revenues and the allowed carrying charge rate related to the delayed residential revenues. In July 2015, the WVPSC issued an order that denied all motions for reconsideration. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. As of June 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding are estimated to be $12 million . In February and March 2015, briefs related to this proceeding were filed by various parties. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 for Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on equity of 10.5% and is proposed to be effective in January 2016, except for the $44 million for environmental investments, which is proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of June 30, 2015, PSO has incurred costs of $140 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that future incremental purchased capacity and energy costs of an estimated $35 million will be incurred related to the environmental compliance plan, due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of June 30, 2015, the net book value of Northeastern Plant, Unit 4 was $95 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies. These additional regulatory assets are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million , excluding AFUDC, would be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider would allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M would defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M did not seek a rate adjustment in this proceeding but sought approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. In April 2015, I&M filed a notice with the IURC to seek approval of the proposed TDSIC Plan excluding $117 million of certain projects that were challenged in this proceeding. In May 2015, the IURC issued an order that denied I&M's TDSIC Plan and Rider. In May 2015, I&M filed a petition for reconsideration and/or rehearing with the IURC and in June 2015, filed a notice of appeal with the Indiana Court of Appeals.
Public Service Co Of Oklahoma [Member]
Rate Matters	RATE MATTERS As discussed in the 2014 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 2014 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 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115 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. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. If the Supreme Court of Ohio upholds its June 2015 order, it would remand the matter back to the PUCO for reinstatement of the WACC rate. Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the ruling in this proceeding, it could impact future net income, cash flows and financial condition. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In July 2014, OPCo submitted a separate application to continue the RSR to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00 /MWh until the balance of the capacity deferrals has been collected. In April 2015, the PUCO issued an order approving the application to continue the RSR, with modifications. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of June 30, 2015 , OPCo's incurred deferred capacity costs balance of $432 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. As provided for in the June 2015 - May 2018 ESP, for delivery starting in June 2015, OPCo now conducts energy and capacity auctions for its entire SSO load. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal included a return on common equity of 10.65% on capital costs for certain riders. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, on rehearing, the PUCO issued an order that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In June 2015, OPCo and various intervenors filed applications for rehearing with the PUCO related to the May 2015 order on rehearing. In July 2015, the PUCO granted the requests for rehearing. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) continued to include the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo filed its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation 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. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of June 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. 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 was held in 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. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of June 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 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 and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery 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 review base rates in 2014 and 2015 and that SWEPCo 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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, which was 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. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which will be effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million , excluding AFUDC. As of June 30, 2015 , SWEPCo has incurred costs of $256 million , including AFUDC, and has remaining contractual construction obligations of $89 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of June 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $484 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million , based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested recovery of $77 million in regulatory assets over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover vegetation management costs, including a return on capital investment. In May 2015, the WVPSC issued an order on the base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million annual delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. In June 2015, the WVPSC staff and intervenors filed motions for reconsideration and clarification related to various issues including recovery of lost revenues and the allowed carrying charge rate related to the delayed residential revenues. In July 2015, the WVPSC issued an order that denied all motions for reconsideration. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. As of June 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding are estimated to be $12 million . In February and March 2015, briefs related to this proceeding were filed by various parties. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 for Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on equity of 10.5% and is proposed to be effective in January 2016, except for the $44 million for environmental investments, which is proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of June 30, 2015, PSO has incurred costs of $140 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that future incremental purchased capacity and energy costs of an estimated $35 million will be incurred related to the environmental compliance plan, due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of June 30, 2015, the net book value of Northeastern Plant, Unit 4 was $95 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies. These additional regulatory assets are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million , excluding AFUDC, would be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider would allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M would defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M did not seek a rate adjustment in this proceeding but sought approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. In April 2015, I&M filed a notice with the IURC to seek approval of the proposed TDSIC Plan excluding $117 million of certain projects that were challenged in this proceeding. In May 2015, the IURC issued an order that denied I&M's TDSIC Plan and Rider. In May 2015, I&M filed a petition for reconsideration and/or rehearing with the IURC and in June 2015, filed a notice of appeal with the Indiana Court of Appeals.
Southwestern Electric Power Co [Member]
Rate Matters	RATE MATTERS As discussed in the 2014 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 2014 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 2015 and updates the 2014 Annual Report. Regulatory Assets Pending Final Regulatory Approval APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115 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. The order also provided a phase-in FAC, which was authorized to be recovered through a non-bypassable surcharge over the period 2012 through 2018. In August 2012, the PUCO issued an order in a separate proceeding which implemented a PIRR to recover deferred fuel costs in rates beginning September 2012. The PUCO ruled that carrying charges should be calculated without an offset for accumulated deferred income taxes and that a long-term debt rate should be applied when collections begin. In November 2012, OPCo appealed that PUCO order to the Supreme Court of Ohio claiming a long-term debt rate modified the previously adjudicated 2009 - 2011 ESP order, which granted a weighted average cost of capital (WACC) rate. In November 2012, the IEU filed an appeal of the PUCO decision that included the argument that carrying costs should be reduced due to an accumulated deferred income tax credit. In June 2015, the Supreme Court of Ohio issued a decision that reversed the PUCO order on the carrying cost rate issue and dismissed the appeal filed by the IEU. In June 2015, the IEU filed a motion for reconsideration with the Supreme Court of Ohio related to the accumulated deferred income tax credit. If the Supreme Court of Ohio upholds its June 2015 order, it would remand the matter back to the PUCO for reinstatement of the WACC rate. Management is unable to predict the outcome of the unresolved litigation discussed above. Depending on the ruling in this proceeding, it could impact future net income, cash flows and financial condition. June 2012 – May 2015 ESP Including Capacity Charge In August 2012, the PUCO issued an order which adopted and modified a new ESP that established base generation rates through May 2015. This ruling was generally upheld in rehearing orders in January and March 2013. In July 2012, the PUCO issued an order in a separate capacity proceeding which stated that OPCo must charge CRES providers the RPM price and authorized OPCo to defer a portion of its incurred capacity costs not recovered from CRES providers up to $188.88 /MW day. The OPCo RPM price collected from CRES providers, which includes reserve margins, was approximately $34 /MW day through May 2014 and $150 /MW day from June 2014 through May 2015. In December 2012, various parties filed notices of appeal of the capacity costs decision with the Supreme Court of Ohio. As part of the August 2012 ESP order, the PUCO established a non-bypassable RSR, effective September 2012. The RSR was collected from customers at $3.50 /MWh through May 2014 and at $4.00 /MWh for the period June 2014 through May 2015, with $1.00 /MWh applied to the recovery of deferred capacity costs. In July 2014, OPCo submitted a separate application to continue the RSR to collect the unrecovered portion of the deferred capacity costs at the rate of $4.00 /MWh until the balance of the capacity deferrals has been collected. In April 2015, the PUCO issued an order approving the application to continue the RSR, with modifications. The order included approval to continue the collection of deferred capacity costs at a rate of $4.00 /MWh beginning June 1, 2015 for approximately 32 months, with carrying costs at a long-term cost of debt rate. Additionally, the order stated that an audit will be conducted of the May 31, 2015 capacity deferral balance, which was $444 million . In May 2015, the PUCO granted intervenors requests for rehearing. As of June 30, 2015 , OPCo's incurred deferred capacity costs balance of $432 million , including debt carrying costs, was recorded in Regulatory Assets on the condensed balance sheet. In 2013, the PUCO issued its Orders on Rehearing for the ESP which generally upheld its August 2012 order. The PUCO clarified that a final reconciliation of revenues and expenses would be permitted for any over- or under-recovery on several riders including fuel. In addition, the PUCO addressed certain issues around the energy auctions while other SSO issues related to the energy auctions were deferred to a separate docket related to the competitive bid process (CBP). In 2013, OPCo and various intervenors filed appeals with the Supreme Court of Ohio challenging portions of the PUCO’s ESP order. Oral arguments at the Supreme Court of Ohio were held in May 2015. In November 2013, the PUCO issued an order approving OPCo’s CBP with modifications. As ordered, in 2014, OPCo conducted multiple energy-only auctions for a total of 100% of the SSO load with delivery beginning April 2014 through May 2015. As provided for in the June 2015 - May 2018 ESP, for delivery starting in June 2015, OPCo now conducts energy and capacity auctions for its entire SSO load. The PUCO also approved the unbundling of the FAC into fixed and energy-related components and an intervenor proposal to blend the $188.88/MW day capacity price in proportion to the percentage of energy planned to be auctioned. Additionally, the PUCO ordered that intervenor concerns related to the recovery of the fixed fuel costs through potentially both the FAC and the approved capacity charges be addressed in subsequent FAC proceedings. In January 2014, the PUCO denied all rehearing requests and agreed to issue a supplemental request for an independent auditor in the 2012 - 2013 FAC proceeding to separately examine the recovery of the fixed fuel costs, including OVEC. In March 2014, the PUCO approved OPCo’s request to implement riders related to the unbundling of the FAC. In October 2014, the independent auditor, selected by the PUCO, filed its report for the period August 2012 through May 2015 with the PUCO. If the PUCO ultimately concludes that a portion of the fixed fuel costs are also recovered through OPCo's $188.88/MW day capacity charge, the independent auditor has recommended a methodology for calculating a refund of a portion of certain fixed fuel costs. The retail share of these fixed fuel costs is approximately $90 million annually. A hearing related to this matter has not been scheduled. Management believes that no over-recovery of costs has occurred and disagrees with the findings in the audit report. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. June 2015 - May 2018 ESP In December 2013, OPCo filed an application with the PUCO to approve an ESP that included proposed rate adjustments and the continuation and modification of certain existing riders, including the Distribution Investment Rider (DIR), effective June 2015 through May 2018. The proposal included a return on common equity of 10.65% on capital costs for certain riders. The proposal also included a purchased power agreement (PPA) rider that would allow retail customers to receive a rate stabilizing charge or credit by hedging market-based prices with a cost-based PPA. The PPA would initially be based upon the OVEC contractual entitlement and could, upon further approval, be expanded to include other contracts involving other Ohio legacy generation assets. In October 2014, OPCo filed a separate application with the PUCO to propose a new extended PPA with AGR for 2,671 MW for inclusion in the PPA rider. In February 2015, the PUCO issued an order approving OPCo's ESP application, subject to certain modifications, with a return on common equity of 10.2% on capital costs for certain riders. The order included (a) approval of the DIR with modified rate caps established by the PUCO, (b) authorization to establish a zero rate rider for OPCo's proposed PPA, (c) the option for OPCo to reapply in a future proceeding with a more detailed PPA proposal and (d) a directive to continue to pursue the transfer of the OVEC contractual entitlement to AGR or to otherwise divest of its interest in OVEC. In May 2015, on rehearing, the PUCO issued an order that increased the DIR rate caps and deferred ruling on all requests for rehearing related to the establishment of the PPA rider. In June 2015, OPCo and various intervenors filed applications for rehearing with the PUCO related to the May 2015 order on rehearing. In July 2015, the PUCO granted the requests for rehearing. In May 2015, OPCo filed an amended PPA application between OPCo and AGR that (a) included OPCo's OVEC contractual entitlement, (b) addressed the PPA requirements set forth in the PUCO's February 2015 order, (c) updated supporting testimony to reflect a current analysis of the PPA proposal and (d) continued to include the 2,671 MW to be available for capacity, energy and ancillary services, produced by AGR over the lives of the respective generating units. If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows and impact financial condition. Significantly Excessive Earnings Test Filings In January 2011, the PUCO issued an order on the 2009 SEET filing. The order gave consideration for a future commitment to invest $20 million to support the development of a large solar farm. In January 2013, the PUCO found there was not a need for the large solar farm. The PUCO noted that OPCo remains obligated to spend $20 million on this solar project or another project. In September 2013, a proposed second phase of OPCo’s gridSMART ® program was filed with the PUCO which included a proposed project to satisfy this PUCO directive. A decision from the PUCO is pending. In June 2015, OPCo filed its 2014 SEET filing with the PUCO. Management believes its financial statements adequately address the impact of 2014 SEET requirements. Corporate Separation In October 2012, the PUCO issued an order which approved the corporate separation 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. 2009 Fuel Adjustment Clause Audit In January 2012, the PUCO issued an order in OPCo’s 2009 FAC that the remaining $65 million in proceeds from a 2008 coal contract settlement agreement be applied against OPCo’s under-recovered fuel balance. In April 2012, on rehearing, the PUCO ordered that the settlement credit only needed to reflect the Ohio retail jurisdictional share of the gain not already flowed through the FAC with carrying charges. As a result, OPCo recorded a $30 million net favorable adjustment on the statement of income in 2012. The January 2012 PUCO order also stated that a consultant should be hired to review the coal reserve valuation and recommend whether any additional value should benefit ratepayers. In September 2014, the Supreme Court of Ohio upheld the PUCO order on appeal. A review of the coal reserve valuation by an outside consultant has not been initiated by the PUCO. If the PUCO ultimately determines that additional amounts should benefit ratepayers as a result of the consultant’s review of the coal reserve valuation, it could reduce future net income and cash flows and impact financial condition. 2012 and 2013 Fuel Adjustment Clause Audits In May 2014, the PUCO-selected outside consultant provided its final report related to its 2012 and 2013 FAC audit which included certain unfavorable recommendations related to the FAC recovery for 2012 and 2013. These recommendations are opposed by OPCo. In addition, the PUCO will consider the results of the final audit of the recovery of fixed fuel costs that was issued in October 2014. See the "June 2012 - May 2015 ESP Including Capacity Charge" section above. If the PUCO orders a reduction to the FAC deferral or a refund to customers, it could reduce future net income and cash flows and impact financial condition. Ormet Ormet, a large aluminum company, had a contract to purchase power from OPCo through 2018. In 2013, Ormet filed for bankruptcy and subsequently shut down operations. In March 2014, the PUCO issued an order in OPCo’s Economic Development Rider (EDR) filing allowing OPCo to include $39 million of Ormet-related foregone revenues in the EDR effective April 2014. The order stated that if the stipulation agreement between OPCo and Ormet is subsequently adopted by the PUCO, OPCo could file an application to modify the EDR rate for the remainder of the period requesting recovery of the remaining $10 million of Ormet deferrals which, as of June 30, 2015 , is recorded in Regulatory Assets on the condensed balance sheet. 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 was held in 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. SWEPCo Rate Matters 2012 Texas Base Rate Case In 2012, SWEPCo filed a request with the PUCT to increase annual base rates primarily due to the completion of the Turk Plant. In 2013, the PUCT issued an order affirming the prudence of the Turk Plant but determined that the Turk Plant’s Texas jurisdictional capital cost cap established in a previous Certificate of Convenience and Necessity case also limited SWEPCo’s recovery of AFUDC in addition to limits on its recovery of cash construction costs. Additionally, the PUCT deferred consideration of the requested increase in depreciation expense related to the change in the 2016 retirement date of the Welsh Plant, Unit 2. As of June 30, 2015 , the net book value of Welsh Plant, Unit 2 was $83 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 and in April 2014, this order became final. In May 2014, intervenors filed appeals of that order with the Texas District Court. In June 2014, SWEPCo intervened in those appeals and filed initial responses. If certain parts of the PUCT order are overturned or if SWEPCo cannot ultimately recover its Texas jurisdictional share of the Turk Plant investment, including AFUDC, or its retirement-related costs and potential fuel or replacement power disallowances related to Welsh Plant, Unit 2, it could reduce future net income and cash flows and impact financial condition. 2012 Louisiana Formula Rate Filing In 2012, SWEPCo initiated a proceeding to establish new formula base rates in Louisiana, including recovery of the Louisiana jurisdictional share (approximately 29% ) of the Turk Plant. In February 2013, a settlement was filed and approved by the LPSC. The settlement increased SWEPCo's Louisiana total rates by approximately $2 million annually, effective March 2013, which consisted of an increase in base rates of approximately $85 million annually offset by a decrease in fuel and other rates of approximately $83 million annually. The March 2013 base rates are based on a 10% return on common equity and cost recovery 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 review base rates in 2014 and 2015 and that SWEPCo 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 December 2014, the LPSC approved a settlement agreement related to the staff review of the cost of service. The settlement agreement reduced the requested revenue increase by $3 million , primarily due to the timing of both the allowed recovery of certain existing regulatory assets and the establishment of a regulatory asset for certain previously expensed costs. If the LPSC orders refunds based upon the pending prudence review of the Turk Plant investment, 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, which was 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. In December 2014, the LPSC approved a partial settlement agreement that included the implementation of the $15 million annual increase in rates effective January 2015. These increases are subject to LPSC staff review and are subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2015 Louisiana Formula Rate Filing In April 2015, SWEPCo filed its formula rate plan for test year 2014 with the LPSC. The filing included a $14 million annual increase, which will be effective August 2015. This increase is subject to LPSC staff review and is subject to refund. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. Welsh Plant, Units 1 and 3 – Environmental Projects To comply with pending Federal EPA regulations, SWEPCo is currently constructing environmental control projects to meet mercury and air toxics standards for Welsh Plant, Units 1 and 3 at a cost of approximately $410 million , excluding AFUDC. Management currently estimates that the total environmental projects to be completed through 2020 for Welsh Plant, Units 1 and 3 will cost approximately $600 million , excluding AFUDC. As of June 30, 2015 , SWEPCo has incurred costs of $256 million , including AFUDC, and has remaining contractual construction obligations of $89 million related to these projects. SWEPCo will seek recovery of these project costs from customers through filings at the state commissions and the FERC. As of June 30, 2015 , the net book value of Welsh Plant, Units 1 and 3 was $484 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. APCo Rate Matters 2014 West Virginia Base Rate Case In June 2014, APCo filed a request with the WVPSC to increase annual base rates by $156 million , based upon a 10.62% return on common equity, to be effective in the second quarter of 2015. The filing included a request to increase generation depreciation rates primarily due to the increase in plant investment and changes in the expected service lives of various generating units. The filing also requested recovery of $77 million in regulatory assets over five years related to 2012 West Virginia storm costs, IGCC and other deferred costs. In addition to the base rate request, the filing also included a request to implement a rider of approximately $38 million annually to recover vegetation management costs, including a return on capital investment. In May 2015, the WVPSC issued an order on the base rate case. Upon implementation of the order in May 2015, and consistent with the WVPSC authorized total revenue, annual base rates were authorized to be increased by $85 million based upon a 9.75% return on common equity. The order included a delayed billing of $22 million of the annual base rate increase to residential customers until July 2016. The order provided for carrying charges based upon a WACC rate for the $22 million annual delayed billing through June 2016, and stated recovery would be addressed in the next ENEC case scheduled for 2016. Additionally, the order included approval of (a) an initial vegetation management rider of $38 million annually, (b) revised deprecation rates, including recovery of plants to be retired and (c) the recovery of $77 million in previously recorded regulatory assets, which will predominantly be recovered over five years. In June 2015, the WVPSC staff and intervenors filed motions for reconsideration and clarification related to various issues including recovery of lost revenues and the allowed carrying charge rate related to the delayed residential revenues. In July 2015, the WVPSC issued an order that denied all motions for reconsideration. 2015 Virginia Regulatory Asset Proceeding In January 2015, the Virginia SCC initiated a separate proceeding to address the proper treatment of APCo’s authorized regulatory assets. As of June 30, 2015 , APCo’s authorized regulatory assets under review in this proceeding are estimated to be $12 million . In February and March 2015, briefs related to this proceeding were filed by various parties. If any of these costs, or any additional costs that may be subject to review, are not recoverable, it could reduce future net income and cash flows and impact financial condition. New Virginia Legislation Affecting Biennial Reviews In February 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amended Virginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennial review, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also preclude the Virginia SCC from performing biennial reviews of APCo’s earnings for the years 2014 through 2017. APCo's financial statements adequately address the impact of these amendments. The new law provides that APCo will absorb its Virginia jurisdictional share of incremental generation and distribution costs incurred during 2014 through 2017 that are associated with severe weather events and/or natural disasters and costs associated with potential impairments related to new carbon emission guidelines issued by the Federal EPA. PSO Rate Matters 2015 Oklahoma Base Rate Case In July 2015, PSO filed a request with the OCC to increase annual revenues by $137 million to recover costs associated with its environmental compliance plan for the Federal EPA’s Regional Haze Rule and Mercury and Air Toxics Standards, and to recover investments and other costs that have increased since the last base rate case. The annual increase consists of (a) a base rate increase of $89 million , which includes $48 million in increased depreciation expense that reflects, among other things, recovery through June 2026 for Northeastern Plant, Units 3 and 4, (b) a rider or base rate increase of $44 million to recover costs for the environmental controls being installed on Northeastern Plant, Unit 3 and the Comanche Plant and (c) a request to include environmental consumable costs in the FAC, estimated to be $4 million annually. The rate increase includes a proposed return on equity of 10.5% and is proposed to be effective in January 2016, except for the $44 million for environmental investments, which is proposed to be effective in March 2016, after the Northeastern Plant, Unit 3 environmental controls go in service. The total estimated cost of the environmental controls to be installed at Northeastern Plant, Unit 3 and the Comanche Plant is $219 million , excluding AFUDC. As of June 30, 2015, PSO has incurred costs of $140 million related to these projects, including AFUDC. In addition, the filing also notified the OCC that future incremental purchased capacity and energy costs of an estimated $35 million will be incurred related to the environmental compliance plan, due to the closure of Northeastern Plant, Unit 4 in April 2016, which would be recovered through the FAC. As of June 30, 2015, the net book value of Northeastern Plant, Unit 4 was $95 million , before cost of removal, including materials and supplies inventory and CWIP. If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. 2014 Oklahoma Base Rate Case In April 2015, the OCC issued an order that approved a non-unanimous stipulation agreement between PSO, the OCC staff and certain intervenors. The approved stipulation provides for no overall change to the transmission rider or to annual revenues, other than additional revenues through a separate rider related to advanced metering costs, and that the terms of the stipulation be effective November 2014. The advanced metering rider provides $24 million of revenues over 14 months beginning in November 2014 and increases to $27 million in 2016. The stipulation also included (a) new depreciation rates for advanced metering investments and existing meters, also effective November 2014, (b) a return on common equity of 9.85% to be used only in the formula to calculate AFUDC, factoring of customer receivables and for riders with an equity component and (c) recovery of regulatory assets for 2013 storms and regulatory case expenses. The advanced metering cost rider was implemented in November 2014. I&M Rate Matters Tanners Creek Plant In October 2014, I&M filed an application with the IURC seeking approval of revised depreciation rates for Rockport Plant, Unit 1 and the Tanners Creek Plant. Upon retirement of the Tanners Creek Plant, I&M proposed that, for purposes of determining its depreciation rates, the net book value of the Tanners Creek Plant be recovered over the remaining life of the Rockport Plant. The new depreciation rates would result in a decrease in I&M's Indiana jurisdictional electric depreciation expense which I&M proposed to reduce customer rates through a credit rider. In May 2015, the IURC issued an order approving I&M's request for revised depreciation rates. In May 2015, Tanners Creek Plant was retired. Upon retirement, $265 million was reclassified as Regulatory Assets on the condensed balance sheet related to the net book value of Tanners Creek Plant and is being amortized over 29 years. An additional $38 million was reclassified as Regulatory Assets on the condensed balance sheet for related asset retirement obligations and materials and supplies. These additional regulatory assets are currently not being amortized, pending regulatory approval. Transmission, Distribution and Storage System Improvement Charge (TDSIC) In October 2014, I&M filed petitions with the IURC for approval of a TDSIC Rider and approval of I&M’s seven-year TDSIC Plan, from 2015 through 2021, for eligible transmission, distribution and storage system improvements. The initial estimated cost of the capital improvements and associated operation and maintenance expenses included in the TDSIC Plan of $787 million , excluding AFUDC, would be updated annually. The TDSIC Plan included distribution investments specific to the Indiana jurisdiction. The TDSIC Rider would allow the periodic adjustment of I&M's rates to provide for timely recovery of 80% of approved TDSIC Plan costs. I&M would defer the remaining 20% of approved TDSIC Plan costs to be recovered in I&M's next general rate case. I&M did not seek a rate adjustment in this proceeding but sought approval of a TDSIC Rider rate adjustment mechanism for subsequent proceedings. In April 2015, I&M filed a notice with the IURC to seek approval of the proposed TDSIC Plan excluding $117 million of certain projects that were challenged in this proceeding. In May 2015, the IURC issued an order that denied I&M's TDSIC Plan and Rider. In May 2015, I&M filed a petition for reconsideration and/or rehearing with the IURC and in June 2015, filed a notice of appeal with the Indiana Court of Appeals.

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies	6 Months Ended
	Jun. 30, 2015
Commitments, Guarantees and Contingencies	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 2014 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 June 30, 2015 , the maximum future payments for letters of credit issued under the revolving credit facilities were $61 million with maturities ranging from October 2015 to June 2016. We issue letters of credit under a $100 million uncommitted facility. As of June 30, 2015 , the maximum future payments for letters of credit issued under the uncommitted facility were $100 million with a maturity of December 2015. An uncommitted facility gives the issuer of the facility the right to accept or decline each request we make under the facility. We have $477 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $483 million . The letters of credit have maturities ranging from March 2016 to July 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2015 , SWEPCo has collected $65 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 $49 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 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, our exposure generally does not exceed the sale price. As of June 30, 2015 , 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 June 30, 2015 , the maximum potential loss for these lease agreements was $30 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 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 $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% 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 $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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of June 30, 2015, I&M's accrual for all of these sites is approximately $9 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. 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 generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation 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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. In July 2015, the plaintiffs responded to the motion for partial judgment and simultaneously moved for partial summary judgment on their claims for breach of the lease and participation agreement. We will continue to defend against the remaining 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. Defendants in these cases, including AEP, filed a petition seeking further review with the U.S. Supreme Court on the preemption issue. AEP also subsequently filed a separate petition with the U.S. Supreme Court seeking review of the personal jurisdiction issue. In July 2014, the U.S. Supreme Court granted the defendants' previously filed petition for further review with the U.S. Supreme Court on the preemption issue. Oral argument occurred in January 2015. In April 2015, the U.S. Supreme Court affirmed the judgment of the U.S. Court of Appeals for the Ninth Circuit on the preemption issue, holding that the plaintiffs' state antitrust claims were not preempted by the Natural Gas Act. The U.S. Supreme Court denied AEP's petition for review of the personal jurisdiction issue shortly thereafter. The cases have been remanded to the district court for further proceedings. We will continue to defend the cases. We believe the provision we have is adequate. We are unable to determine the amount of potential additional 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. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. We will continue to defend the case. We are unable to determine a range of potential losses that are reasonably possible of occurring. National Do Not Call Registry Lawsuit In May 2014, AEP Energy was served with a complaint filed in the U.S. District Court for the Northern District of Illinois, alleging violations of the Telephone Consumer Protection Act (TCPA). The plaintiff alleges that he received telemarketing calls on behalf of AEP Energy despite having registered his telephone number on the National Do Not Call Registry. Plaintiff seeks to represent a class of persons who allegedly received such calls. Plaintiff seeks statutory damages under the TCPA on behalf of himself and the alleged class as well as injunctive relief. As a result of a mediation held in October 2014, the parties reached an agreement in principle, subject to final documentation and preliminary and final court approval. In April 2015, we filed a motion with the court for preliminary approval of the settlement. In June 2015, the court granted preliminary approval of the settlement. A final approval hearing related to this matter has been scheduled for September 2015. We will continue to defend the case. We believe the provision we have is adequate. We are unable to determine the amount of potential additional losses that are reasonably possible of occurring. Gavin Landfill Litigation In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, we filed a motion to dismiss the complaint, contending the case should be filed in Ohio. That motion 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.
Appalachian Power Co [Member]
Commitments, Guarantees and Contingencies	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 2014 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 and OPCo 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 June 30, 2015 , the maximum future payments for letters of credit issued under the revolving credit facilities were as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2015 , SWEPCo has collected $65 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 $49 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 June 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity 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 June 30, 2015 , 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: Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825 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 $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% 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 $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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of June 30, 2015, I&M's accrual for all of these sites is approximately $9 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – 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 generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – 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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. In July 2015, the plaintiffs responded to the motion for partial judgment and simultaneously moved for partial summary judgment on their claims for breach of the lease and participation agreement. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. 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. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. That motion 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.
Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies	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 2014 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 and OPCo 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 June 30, 2015 , the maximum future payments for letters of credit issued under the revolving credit facilities were as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2015 , SWEPCo has collected $65 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 $49 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 June 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity 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 June 30, 2015 , 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: Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825 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 $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% 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 $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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of June 30, 2015, I&M's accrual for all of these sites is approximately $9 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – 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 generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – 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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. In July 2015, the plaintiffs responded to the motion for partial judgment and simultaneously moved for partial summary judgment on their claims for breach of the lease and participation agreement. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. 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. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. That motion 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	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 2014 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 and OPCo 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 June 30, 2015 , the maximum future payments for letters of credit issued under the revolving credit facilities were as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2015 , SWEPCo has collected $65 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 $49 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 June 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity 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 June 30, 2015 , 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: Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825 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 $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% 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 $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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of June 30, 2015, I&M's accrual for all of these sites is approximately $9 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – 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 generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – 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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. In July 2015, the plaintiffs responded to the motion for partial judgment and simultaneously moved for partial summary judgment on their claims for breach of the lease and participation agreement. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. 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. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. That motion 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.
Public Service Co Of Oklahoma [Member]
Commitments, Guarantees and Contingencies	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 2014 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 and OPCo 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 June 30, 2015 , the maximum future payments for letters of credit issued under the revolving credit facilities were as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2015 , SWEPCo has collected $65 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 $49 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 June 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity 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 June 30, 2015 , 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: Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825 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 $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% 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 $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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of June 30, 2015, I&M's accrual for all of these sites is approximately $9 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – 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 generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – 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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. In July 2015, the plaintiffs responded to the motion for partial judgment and simultaneously moved for partial summary judgment on their claims for breach of the lease and participation agreement. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. 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. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. That motion 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.
Southwestern Electric Power Co [Member]
Commitments, Guarantees and Contingencies	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 2014 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 and OPCo 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 June 30, 2015 , the maximum future payments for letters of credit issued under the revolving credit facilities were as follows: Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016 The Registrant Subsidiaries have $307 million of variable rate Pollution Control Bonds supported by bilateral letters of credit for $310 million as follows: Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017 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 $58 million . Actual reclamation costs could vary due to period inflation and any changes to actual mine reclamation. As of June 30, 2015 , SWEPCo has collected $65 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 $49 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 June 30, 2015 , there were no material liabilities recorded for any indemnifications. APCo, I&M and OPCo are jointly and severally liable for activity conducted by AEPSC on behalf of AEP companies related to power purchase and sale activity 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 June 30, 2015 , 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: Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825 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 $11 million and $12 million for I&M and SWEPCo, respectively, for the remaining railcars as of June 30, 2015 . Under the lease agreement, the lessor is guaranteed that the sale proceeds under a return-and-sale option will equal at least a lessee obligation amount specified in the lease, which declines from 83% 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 $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. In 2014, I&M recorded an accrual for remediation at certain additional sites in Michigan. As a result of receiving approval of completed remediation work from the MDEQ in March 2015, I&M's accrual for all of these sites was reduced. As of June 30, 2015, I&M's accrual for all of these sites is approximately $9 million . As the remediation work is completed, I&M’s cost may change as new information becomes available concerning either the level of contamination at the sites or changes in the scope of remediation. Management cannot predict the amount of additional cost, if any. NUCLEAR CONTINGENCIES – 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 generation units, for a nuclear power plant incident at any nuclear plant in the U.S. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. OPERATIONAL CONTINGENCIES Rockport Plant Litigation – 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. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M. In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissed certain of the plaintiffs’ claims. Several claims remain, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of good faith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach of participation agreement claim as well as any claim for indemnification of costs associated with this case. In July 2015, the plaintiffs responded to the motion for partial judgment and simultaneously moved for partial summary judgment on their claims for breach of the lease and participation agreement. Management will continue to defend against the remaining claims. Management is unable to determine a range of potential losses that are reasonably possible of occurring. 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. Notice was given to all potential class members and an additional 44 individuals opted in to the class, bringing the plaintiff class to 80 current and former employees. Two plaintiffs have since dismissed their claims without prejudice, leaving 78 plaintiffs. Management will continue to defend the case. Management is unable to determine a range of potential losses that are reasonably possible of occurring. Gavin Landfill Litigation – Affecting OPCo In August 2014, a complaint was filed in the Mason County, West Virginia Circuit Court against AEP, AEPSC, OPCo and an individual supervisor alleging wrongful death and personal injury/illness claims arising out of purported exposure to coal combustion by-product waste at the Gavin Plant landfill. The lawsuit was filed on behalf of 77 plaintiffs, consisting of 39 current and former contractors of the landfill and 38 family members of those contractors. Eleven of the family members are pursuing personal injury/illness claims and the remainder are pursuing loss of consortium claims. The plaintiffs seek compensatory and punitive damages, as well as medical monitoring. In September 2014, management filed a motion to dismiss the complaint, contending the case should be filed in Ohio. That motion 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.

Benefit Plans

Benefit Plans	6 Months Ended
	Jun. 30, 2015
Benefit Plans	BENEFIT PLANS We sponsor a qualified pension plan and two unfunded nonqualified pension plans. Substantially all of our employees are covered by the qualified plan or both the qualified and a nonqualified pension plan. We sponsor OPEB plans to provide health and life insurance benefits for retired employees. Components of Net Periodic Benefit Cost The following tables provide the components of our net periodic benefit cost (credit) for the plans for the three and six months ended June 30, 2015 and 2014 : Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in millions) Service Cost $ 24 $ 18 $ 3 $ 3 Interest Cost 52 56 14 17 Expected Return on Plan Assets (68 ) (65 ) (27 ) (28 ) Amortization of Prior Service Credit — — (17 ) (17 ) Amortization of Net Actuarial Loss 26 31 4 6 Net Periodic Benefit Cost (Credit) $ 34 $ 40 $ (23 ) $ (19 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in millions) Service Cost $ 47 $ 36 $ 6 $ 7 Interest Cost 103 111 28 34 Expected Return on Plan Assets (137 ) (131 ) (55 ) (56 ) Amortization of Prior Service Cost (Credit) 1 1 (34 ) (34 ) Amortization of Net Actuarial Loss 53 62 9 11 Net Periodic Benefit Cost (Credit) $ 67 $ 79 $ (46 ) $ (38 )
Appalachian Power Co [Member]
Benefit Plans	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 and six months ended June 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 285 $ 362 Interest Cost 6,679 7,406 2,585 3,197 Expected Return on Plan Assets (8,746 ) (8,481 ) (4,529 ) (4,633 ) Amortization of Prior Service Cost (Credit) 45 49 (2,512 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,148 899 1,145 Net Periodic Benefit Cost (Credit) $ 3,627 $ 4,881 $ (3,272 ) $ (2,441 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,350 $ 3,518 $ 571 $ 724 Interest Cost 13,358 14,812 5,169 6,394 Expected Return on Plan Assets (17,491 ) (16,963 ) (9,058 ) (9,266 ) Amortization of Prior Service Cost (Credit) 90 99 (5,025 ) (5,025 ) Amortization of Net Actuarial Loss 6,947 8,296 1,799 2,291 Net Periodic Benefit Cost (Credit) $ 7,254 $ 9,762 $ (6,544 ) $ (4,882 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 407 $ 487 Interest Cost 6,115 6,574 1,592 1,910 Expected Return on Plan Assets (8,116 ) (7,748 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 46 48 (2,356 ) (2,356 ) Amortization of Net Actuarial Loss 3,144 3,646 507 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,154 ) $ (2,730 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,434 $ 5,034 $ 813 $ 974 Interest Cost 12,230 13,147 3,184 3,819 Expected Return on Plan Assets (16,232 ) (15,496 ) (6,608 ) (6,727 ) Amortization of Prior Service Cost (Credit) 91 97 (4,711 ) (4,711 ) Amortization of Net Actuarial Loss 6,289 7,292 1,013 1,184 Net Periodic Benefit Cost (Credit) $ 8,812 $ 10,074 $ (6,309 ) $ (5,461 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,672 $ 1,285 $ 215 $ 257 Interest Cost 5,070 5,526 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,606 ) (3,378 ) (3,380 ) Amortization of Prior Service Cost (Credit) 35 39 (1,730 ) (1,730 ) Amortization of Net Actuarial Loss 2,644 3,105 518 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,349 $ (2,760 ) $ (2,358 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,344 $ 2,570 $ 431 $ 513 Interest Cost 10,140 11,052 3,230 3,801 Expected Return on Plan Assets (13,756 ) (13,213 ) (6,754 ) (6,760 ) Amortization of Prior Service Cost (Credit) 70 78 (3,461 ) (3,461 ) Amortization of Net Actuarial Loss 5,288 6,211 1,035 1,190 Net Periodic Benefit Cost (Credit) $ 5,086 $ 6,698 $ (5,519 ) $ (4,717 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,599 $ 1,302 $ 169 $ 210 Interest Cost 2,732 3,014 759 894 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,577 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,073 ) Amortization of Net Actuarial Loss 1,417 1,688 241 277 Net Periodic Benefit Cost (Credit) $ 2,025 $ 2,427 $ (1,480 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,198 $ 2,604 $ 339 $ 420 Interest Cost 5,463 6,028 1,518 1,787 Expected Return on Plan Assets (7,572 ) (7,302 ) (3,154 ) (3,150 ) Amortization of Prior Service Cost (Credit) 126 148 (2,145 ) (2,145 ) Amortization of Net Actuarial Loss 2,834 3,376 483 554 Net Periodic Benefit Cost (Credit) $ 4,049 $ 4,854 $ (2,959 ) $ (2,534 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,082 $ 1,654 $ 210 $ 253 Interest Cost 2,932 3,162 838 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,736 ) (1,754 ) Amortization of Prior Service Cost (Credit) 77 88 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,507 1,762 266 308 Net Periodic Benefit Cost (Credit) $ 2,590 $ 2,809 $ (1,711 ) $ (1,484 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,163 $ 3,309 $ 421 $ 506 Interest Cost 5,864 6,325 1,675 1,996 Expected Return on Plan Assets (8,016 ) (7,714 ) (3,471 ) (3,508 ) Amortization of Prior Service Cost (Credit) 154 175 (2,578 ) (2,578 ) Amortization of Net Actuarial Loss 3,014 3,523 532 617 Net Periodic Benefit Cost (Credit) $ 5,179 $ 5,618 $ (3,421 ) $ (2,967 )
Indiana Michigan Power Co [Member]
Benefit Plans	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 and six months ended June 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 285 $ 362 Interest Cost 6,679 7,406 2,585 3,197 Expected Return on Plan Assets (8,746 ) (8,481 ) (4,529 ) (4,633 ) Amortization of Prior Service Cost (Credit) 45 49 (2,512 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,148 899 1,145 Net Periodic Benefit Cost (Credit) $ 3,627 $ 4,881 $ (3,272 ) $ (2,441 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,350 $ 3,518 $ 571 $ 724 Interest Cost 13,358 14,812 5,169 6,394 Expected Return on Plan Assets (17,491 ) (16,963 ) (9,058 ) (9,266 ) Amortization of Prior Service Cost (Credit) 90 99 (5,025 ) (5,025 ) Amortization of Net Actuarial Loss 6,947 8,296 1,799 2,291 Net Periodic Benefit Cost (Credit) $ 7,254 $ 9,762 $ (6,544 ) $ (4,882 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 407 $ 487 Interest Cost 6,115 6,574 1,592 1,910 Expected Return on Plan Assets (8,116 ) (7,748 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 46 48 (2,356 ) (2,356 ) Amortization of Net Actuarial Loss 3,144 3,646 507 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,154 ) $ (2,730 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,434 $ 5,034 $ 813 $ 974 Interest Cost 12,230 13,147 3,184 3,819 Expected Return on Plan Assets (16,232 ) (15,496 ) (6,608 ) (6,727 ) Amortization of Prior Service Cost (Credit) 91 97 (4,711 ) (4,711 ) Amortization of Net Actuarial Loss 6,289 7,292 1,013 1,184 Net Periodic Benefit Cost (Credit) $ 8,812 $ 10,074 $ (6,309 ) $ (5,461 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,672 $ 1,285 $ 215 $ 257 Interest Cost 5,070 5,526 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,606 ) (3,378 ) (3,380 ) Amortization of Prior Service Cost (Credit) 35 39 (1,730 ) (1,730 ) Amortization of Net Actuarial Loss 2,644 3,105 518 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,349 $ (2,760 ) $ (2,358 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,344 $ 2,570 $ 431 $ 513 Interest Cost 10,140 11,052 3,230 3,801 Expected Return on Plan Assets (13,756 ) (13,213 ) (6,754 ) (6,760 ) Amortization of Prior Service Cost (Credit) 70 78 (3,461 ) (3,461 ) Amortization of Net Actuarial Loss 5,288 6,211 1,035 1,190 Net Periodic Benefit Cost (Credit) $ 5,086 $ 6,698 $ (5,519 ) $ (4,717 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,599 $ 1,302 $ 169 $ 210 Interest Cost 2,732 3,014 759 894 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,577 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,073 ) Amortization of Net Actuarial Loss 1,417 1,688 241 277 Net Periodic Benefit Cost (Credit) $ 2,025 $ 2,427 $ (1,480 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,198 $ 2,604 $ 339 $ 420 Interest Cost 5,463 6,028 1,518 1,787 Expected Return on Plan Assets (7,572 ) (7,302 ) (3,154 ) (3,150 ) Amortization of Prior Service Cost (Credit) 126 148 (2,145 ) (2,145 ) Amortization of Net Actuarial Loss 2,834 3,376 483 554 Net Periodic Benefit Cost (Credit) $ 4,049 $ 4,854 $ (2,959 ) $ (2,534 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,082 $ 1,654 $ 210 $ 253 Interest Cost 2,932 3,162 838 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,736 ) (1,754 ) Amortization of Prior Service Cost (Credit) 77 88 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,507 1,762 266 308 Net Periodic Benefit Cost (Credit) $ 2,590 $ 2,809 $ (1,711 ) $ (1,484 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,163 $ 3,309 $ 421 $ 506 Interest Cost 5,864 6,325 1,675 1,996 Expected Return on Plan Assets (8,016 ) (7,714 ) (3,471 ) (3,508 ) Amortization of Prior Service Cost (Credit) 154 175 (2,578 ) (2,578 ) Amortization of Net Actuarial Loss 3,014 3,523 532 617 Net Periodic Benefit Cost (Credit) $ 5,179 $ 5,618 $ (3,421 ) $ (2,967 )
Ohio Power Co [Member]
Benefit Plans	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 and six months ended June 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 285 $ 362 Interest Cost 6,679 7,406 2,585 3,197 Expected Return on Plan Assets (8,746 ) (8,481 ) (4,529 ) (4,633 ) Amortization of Prior Service Cost (Credit) 45 49 (2,512 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,148 899 1,145 Net Periodic Benefit Cost (Credit) $ 3,627 $ 4,881 $ (3,272 ) $ (2,441 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,350 $ 3,518 $ 571 $ 724 Interest Cost 13,358 14,812 5,169 6,394 Expected Return on Plan Assets (17,491 ) (16,963 ) (9,058 ) (9,266 ) Amortization of Prior Service Cost (Credit) 90 99 (5,025 ) (5,025 ) Amortization of Net Actuarial Loss 6,947 8,296 1,799 2,291 Net Periodic Benefit Cost (Credit) $ 7,254 $ 9,762 $ (6,544 ) $ (4,882 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 407 $ 487 Interest Cost 6,115 6,574 1,592 1,910 Expected Return on Plan Assets (8,116 ) (7,748 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 46 48 (2,356 ) (2,356 ) Amortization of Net Actuarial Loss 3,144 3,646 507 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,154 ) $ (2,730 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,434 $ 5,034 $ 813 $ 974 Interest Cost 12,230 13,147 3,184 3,819 Expected Return on Plan Assets (16,232 ) (15,496 ) (6,608 ) (6,727 ) Amortization of Prior Service Cost (Credit) 91 97 (4,711 ) (4,711 ) Amortization of Net Actuarial Loss 6,289 7,292 1,013 1,184 Net Periodic Benefit Cost (Credit) $ 8,812 $ 10,074 $ (6,309 ) $ (5,461 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,672 $ 1,285 $ 215 $ 257 Interest Cost 5,070 5,526 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,606 ) (3,378 ) (3,380 ) Amortization of Prior Service Cost (Credit) 35 39 (1,730 ) (1,730 ) Amortization of Net Actuarial Loss 2,644 3,105 518 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,349 $ (2,760 ) $ (2,358 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,344 $ 2,570 $ 431 $ 513 Interest Cost 10,140 11,052 3,230 3,801 Expected Return on Plan Assets (13,756 ) (13,213 ) (6,754 ) (6,760 ) Amortization of Prior Service Cost (Credit) 70 78 (3,461 ) (3,461 ) Amortization of Net Actuarial Loss 5,288 6,211 1,035 1,190 Net Periodic Benefit Cost (Credit) $ 5,086 $ 6,698 $ (5,519 ) $ (4,717 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,599 $ 1,302 $ 169 $ 210 Interest Cost 2,732 3,014 759 894 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,577 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,073 ) Amortization of Net Actuarial Loss 1,417 1,688 241 277 Net Periodic Benefit Cost (Credit) $ 2,025 $ 2,427 $ (1,480 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,198 $ 2,604 $ 339 $ 420 Interest Cost 5,463 6,028 1,518 1,787 Expected Return on Plan Assets (7,572 ) (7,302 ) (3,154 ) (3,150 ) Amortization of Prior Service Cost (Credit) 126 148 (2,145 ) (2,145 ) Amortization of Net Actuarial Loss 2,834 3,376 483 554 Net Periodic Benefit Cost (Credit) $ 4,049 $ 4,854 $ (2,959 ) $ (2,534 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,082 $ 1,654 $ 210 $ 253 Interest Cost 2,932 3,162 838 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,736 ) (1,754 ) Amortization of Prior Service Cost (Credit) 77 88 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,507 1,762 266 308 Net Periodic Benefit Cost (Credit) $ 2,590 $ 2,809 $ (1,711 ) $ (1,484 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,163 $ 3,309 $ 421 $ 506 Interest Cost 5,864 6,325 1,675 1,996 Expected Return on Plan Assets (8,016 ) (7,714 ) (3,471 ) (3,508 ) Amortization of Prior Service Cost (Credit) 154 175 (2,578 ) (2,578 ) Amortization of Net Actuarial Loss 3,014 3,523 532 617 Net Periodic Benefit Cost (Credit) $ 5,179 $ 5,618 $ (3,421 ) $ (2,967 )
Public Service Co Of Oklahoma [Member]
Benefit Plans	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 and six months ended June 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 285 $ 362 Interest Cost 6,679 7,406 2,585 3,197 Expected Return on Plan Assets (8,746 ) (8,481 ) (4,529 ) (4,633 ) Amortization of Prior Service Cost (Credit) 45 49 (2,512 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,148 899 1,145 Net Periodic Benefit Cost (Credit) $ 3,627 $ 4,881 $ (3,272 ) $ (2,441 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,350 $ 3,518 $ 571 $ 724 Interest Cost 13,358 14,812 5,169 6,394 Expected Return on Plan Assets (17,491 ) (16,963 ) (9,058 ) (9,266 ) Amortization of Prior Service Cost (Credit) 90 99 (5,025 ) (5,025 ) Amortization of Net Actuarial Loss 6,947 8,296 1,799 2,291 Net Periodic Benefit Cost (Credit) $ 7,254 $ 9,762 $ (6,544 ) $ (4,882 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 407 $ 487 Interest Cost 6,115 6,574 1,592 1,910 Expected Return on Plan Assets (8,116 ) (7,748 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 46 48 (2,356 ) (2,356 ) Amortization of Net Actuarial Loss 3,144 3,646 507 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,154 ) $ (2,730 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,434 $ 5,034 $ 813 $ 974 Interest Cost 12,230 13,147 3,184 3,819 Expected Return on Plan Assets (16,232 ) (15,496 ) (6,608 ) (6,727 ) Amortization of Prior Service Cost (Credit) 91 97 (4,711 ) (4,711 ) Amortization of Net Actuarial Loss 6,289 7,292 1,013 1,184 Net Periodic Benefit Cost (Credit) $ 8,812 $ 10,074 $ (6,309 ) $ (5,461 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,672 $ 1,285 $ 215 $ 257 Interest Cost 5,070 5,526 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,606 ) (3,378 ) (3,380 ) Amortization of Prior Service Cost (Credit) 35 39 (1,730 ) (1,730 ) Amortization of Net Actuarial Loss 2,644 3,105 518 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,349 $ (2,760 ) $ (2,358 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,344 $ 2,570 $ 431 $ 513 Interest Cost 10,140 11,052 3,230 3,801 Expected Return on Plan Assets (13,756 ) (13,213 ) (6,754 ) (6,760 ) Amortization of Prior Service Cost (Credit) 70 78 (3,461 ) (3,461 ) Amortization of Net Actuarial Loss 5,288 6,211 1,035 1,190 Net Periodic Benefit Cost (Credit) $ 5,086 $ 6,698 $ (5,519 ) $ (4,717 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,599 $ 1,302 $ 169 $ 210 Interest Cost 2,732 3,014 759 894 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,577 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,073 ) Amortization of Net Actuarial Loss 1,417 1,688 241 277 Net Periodic Benefit Cost (Credit) $ 2,025 $ 2,427 $ (1,480 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,198 $ 2,604 $ 339 $ 420 Interest Cost 5,463 6,028 1,518 1,787 Expected Return on Plan Assets (7,572 ) (7,302 ) (3,154 ) (3,150 ) Amortization of Prior Service Cost (Credit) 126 148 (2,145 ) (2,145 ) Amortization of Net Actuarial Loss 2,834 3,376 483 554 Net Periodic Benefit Cost (Credit) $ 4,049 $ 4,854 $ (2,959 ) $ (2,534 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,082 $ 1,654 $ 210 $ 253 Interest Cost 2,932 3,162 838 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,736 ) (1,754 ) Amortization of Prior Service Cost (Credit) 77 88 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,507 1,762 266 308 Net Periodic Benefit Cost (Credit) $ 2,590 $ 2,809 $ (1,711 ) $ (1,484 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,163 $ 3,309 $ 421 $ 506 Interest Cost 5,864 6,325 1,675 1,996 Expected Return on Plan Assets (8,016 ) (7,714 ) (3,471 ) (3,508 ) Amortization of Prior Service Cost (Credit) 154 175 (2,578 ) (2,578 ) Amortization of Net Actuarial Loss 3,014 3,523 532 617 Net Periodic Benefit Cost (Credit) $ 5,179 $ 5,618 $ (3,421 ) $ (2,967 )
Southwestern Electric Power Co [Member]
Benefit Plans	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 and six months ended June 30, 2015 and 2014 : APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 285 $ 362 Interest Cost 6,679 7,406 2,585 3,197 Expected Return on Plan Assets (8,746 ) (8,481 ) (4,529 ) (4,633 ) Amortization of Prior Service Cost (Credit) 45 49 (2,512 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,148 899 1,145 Net Periodic Benefit Cost (Credit) $ 3,627 $ 4,881 $ (3,272 ) $ (2,441 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,350 $ 3,518 $ 571 $ 724 Interest Cost 13,358 14,812 5,169 6,394 Expected Return on Plan Assets (17,491 ) (16,963 ) (9,058 ) (9,266 ) Amortization of Prior Service Cost (Credit) 90 99 (5,025 ) (5,025 ) Amortization of Net Actuarial Loss 6,947 8,296 1,799 2,291 Net Periodic Benefit Cost (Credit) $ 7,254 $ 9,762 $ (6,544 ) $ (4,882 ) I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 407 $ 487 Interest Cost 6,115 6,574 1,592 1,910 Expected Return on Plan Assets (8,116 ) (7,748 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 46 48 (2,356 ) (2,356 ) Amortization of Net Actuarial Loss 3,144 3,646 507 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,154 ) $ (2,730 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,434 $ 5,034 $ 813 $ 974 Interest Cost 12,230 13,147 3,184 3,819 Expected Return on Plan Assets (16,232 ) (15,496 ) (6,608 ) (6,727 ) Amortization of Prior Service Cost (Credit) 91 97 (4,711 ) (4,711 ) Amortization of Net Actuarial Loss 6,289 7,292 1,013 1,184 Net Periodic Benefit Cost (Credit) $ 8,812 $ 10,074 $ (6,309 ) $ (5,461 ) OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,672 $ 1,285 $ 215 $ 257 Interest Cost 5,070 5,526 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,606 ) (3,378 ) (3,380 ) Amortization of Prior Service Cost (Credit) 35 39 (1,730 ) (1,730 ) Amortization of Net Actuarial Loss 2,644 3,105 518 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,349 $ (2,760 ) $ (2,358 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,344 $ 2,570 $ 431 $ 513 Interest Cost 10,140 11,052 3,230 3,801 Expected Return on Plan Assets (13,756 ) (13,213 ) (6,754 ) (6,760 ) Amortization of Prior Service Cost (Credit) 70 78 (3,461 ) (3,461 ) Amortization of Net Actuarial Loss 5,288 6,211 1,035 1,190 Net Periodic Benefit Cost (Credit) $ 5,086 $ 6,698 $ (5,519 ) $ (4,717 ) PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,599 $ 1,302 $ 169 $ 210 Interest Cost 2,732 3,014 759 894 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,577 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,073 ) Amortization of Net Actuarial Loss 1,417 1,688 241 277 Net Periodic Benefit Cost (Credit) $ 2,025 $ 2,427 $ (1,480 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,198 $ 2,604 $ 339 $ 420 Interest Cost 5,463 6,028 1,518 1,787 Expected Return on Plan Assets (7,572 ) (7,302 ) (3,154 ) (3,150 ) Amortization of Prior Service Cost (Credit) 126 148 (2,145 ) (2,145 ) Amortization of Net Actuarial Loss 2,834 3,376 483 554 Net Periodic Benefit Cost (Credit) $ 4,049 $ 4,854 $ (2,959 ) $ (2,534 ) SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,082 $ 1,654 $ 210 $ 253 Interest Cost 2,932 3,162 838 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,736 ) (1,754 ) Amortization of Prior Service Cost (Credit) 77 88 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,507 1,762 266 308 Net Periodic Benefit Cost (Credit) $ 2,590 $ 2,809 $ (1,711 ) $ (1,484 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,163 $ 3,309 $ 421 $ 506 Interest Cost 5,864 6,325 1,675 1,996 Expected Return on Plan Assets (8,016 ) (7,714 ) (3,471 ) (3,508 ) Amortization of Prior Service Cost (Credit) 154 175 (2,578 ) (2,578 ) Amortization of Net Actuarial Loss 3,014 3,523 532 617 Net Periodic Benefit Cost (Credit) $ 5,179 $ 5,618 $ (3,421 ) $ (2,967 )

Business Segments

Business Segments	6 Months Ended
	Jun. 30, 2015
Business Segments	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. 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 and capacity to serve SSO customers and provides transmission and distribution services for all connected load. AEP Transmission Holdco • Development, construction and operation of transmission facilities through investments in 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 operations 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 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 income statement information for the three and six months ended June 30, 2015 and 2014 and reportable segment balance sheet information as of June 30, 2015 and December 31, 2014 . These amounts include certain estimates and allocations where necessary. Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,159 $ 1,008 $ 25 $ 628 $ 115 $ 7 $ — (c) $ 3,942 Other Operating Segments 24 53 74 173 13 17 (354 ) — Total Revenues $ 2,183 $ 1,061 $ 99 $ 801 $ 128 $ 24 $ (354 ) $ 3,942 Net Income (Loss) $ 208 $ 78 $ 65 $ 82 $ 1 $ (3 ) $ — $ 431 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,236 (b) $ 1,064 $ 21 $ 573 (b) $ 140 $ 10 $ — (c) $ 4,044 Other Operating Segments 16 (b) 70 36 340 (b) 20 12 (494 ) — Total Revenues $ 2,252 $ 1,134 $ 57 $ 913 $ 160 $ 22 $ (494 ) $ 4,044 Net Income (Loss) $ 155 $ 90 $ 47 $ 98 $ 3 $ (2 ) $ — $ 391 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended Revenues from: External Customers $ 4,646 $ 2,214 $ 47 $ 1,487 $ 243 $ 13 $ — (c) $ 8,650 Other Operating Segments 42 117 110 484 24 37 (814 ) — Total Revenues $ 4,688 $ 2,331 $ 157 $ 1,971 $ 267 $ 50 $ (814 ) $ 8,650 Net Income (Loss) $ 508 $ 175 $ 102 $ 269 $ 12 $ (4 ) $ — $ 1,062 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended Revenues from: External Customers $ 4,785 (b) $ 2,225 $ 33 $ 1,394 (b) $ 286 $ 20 $ (51 ) (c) $ 8,692 Other Operating Segments 53 (b) 124 52 770 (b) 39 28 (1,066 ) — Total Revenues $ 4,838 $ 2,349 $ 85 $ 2,164 $ 325 $ 48 $ (1,117 ) $ 8,692 Net Income (Loss) $ 434 $ 187 $ 71 $ 261 $ 6 $ (7 ) $ — $ 952 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) June 30, 2015 Total Property, Plant and Equipment $ 39,561 $ 13,506 $ 3,275 $ 7,456 $ 726 $ 357 $ (279 ) (d) $ 64,602 Accumulated Depreciation and Amortization 12,343 3,565 34 3,344 227 181 (105 ) (d) 19,589 Total Property Plant and Equipment - Net $ 27,218 $ 9,941 $ 3,241 $ 4,112 $ 499 $ 176 $ (174 ) (d) $ 45,013 Total Assets $ 35,316 $ 14,351 $ 4,036 $ 5,668 $ 756 $ 21,599 $ (20,788 ) (d) (e) $ 60,938 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 894 678 — 240 3 2 — 1,817 Long-term Debt: Affiliated 20 — — 32 — — (52 ) — Non-Affiliated 10,146 4,729 1,315 648 79 844 — 17,761 Total Long-term Debt $ 11,060 $ 5,407 $ 1,315 $ 920 $ 82 $ 846 $ (52 ) $ 19,578 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2014 Total Property, Plant and Equipment $ 39,402 $ 13,024 $ 2,714 $ 8,394 $ 700 $ 343 $ (272 ) (d) $ 64,305 Accumulated Depreciation and Amortization 12,773 3,481 25 3,603 217 188 (99 ) (d) 20,188 Total Property Plant and Equipment - Net $ 26,629 $ 9,543 $ 2,689 $ 4,791 $ 483 $ 155 $ (173 ) (d) $ 44,117 Total Assets $ 33,750 $ 14,495 $ 3,575 $ 6,329 $ 749 $ 21,081 $ (20,346 ) (d) (e) $ 59,633 Long-term Debt Due Within One Year: Affiliated $ 111 $ — $ — $ 86 $ — $ — $ (197 ) $ — Non-Affiliated 1,352 405 — 740 3 3 — 2,503 Long-term Debt: Affiliated 20 — — 32 — — (52 ) — Non-Affiliated 8,634 5,256 1,153 217 80 841 — 16,181 Total Long-term Debt $ 10,117 $ 5,661 $ 1,153 $ 1,075 $ 83 $ 844 $ (249 ) $ 18,684 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes the impact of corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies.
Appalachian Power Co [Member]
Business Segments	BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Indiana Michigan Power Co [Member]
Business Segments	BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Ohio Power Co [Member]
Business Segments	BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Public Service Co Of Oklahoma [Member]
Business Segments	BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.
Southwestern Electric Power Co [Member]
Business Segments	BUSINESS SEGMENTS The Registrant Subsidiaries each have one reportable segment, an integrated electricity generation, transmission and distribution business, except OPCo, an electricity transmission and distribution business that started in 2014. The Registrant Subsidiaries’ other activities are insignificant. The Registrant Subsidiaries’ operations are managed on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight on the business process, cost structures and operating results.

Derivatives and Hedging

Derivatives and Hedging	6 Months Ended
	Jun. 30, 2015
Derivatives and Hedging	DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS We are exposed to certain market risks as a major power producer and participant in the wholesale electricity, natural gas, coal and emission allowance markets. 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 June 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments Volume June 30, December 31, Unit of Measure Primary Risk Exposure (in millions) Commodity: Power 440 334 MWhs Coal 2 3 Tons Natural Gas 73 106 MMBtus Heating Oil and Gasoline 8 6 Gallons Interest Rate $ 129 $ 152 USD Interest Rate and Foreign Currency $ 564 $ 815 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 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. In March 2014, these contracts were 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 June 30, 2015 and December 31, 2014 condensed balance sheets, we netted $3 million and $4 million , respectively, of cash collateral received from third parties against short-term and long-term risk management assets and $27 million and $35 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 June 30, 2015 and December 31, 2014 : Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 390 $ 22 $ 2 $ 414 $ (242 ) $ 172 Long-term Risk Management Assets 451 4 — 455 (92 ) 363 Total Assets 841 26 2 869 (334 ) 535 Current Risk Management Liabilities 311 18 1 330 (252 ) 78 Long-term Risk Management Liabilities 258 17 5 280 (106 ) 174 Total Liabilities 569 35 6 610 (358 ) 252 Total MTM Derivative Contract Net Assets (Liabilities) $ 272 $ (9 ) $ (4 ) $ 259 $ 24 $ 283 Fair Value of Derivative Instruments December 31, 2014 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 392 $ 30 $ 3 $ 425 $ (247 ) $ 178 Long-term Risk Management Assets 367 3 — 370 (76 ) 294 Total Assets 759 33 3 795 (323 ) 472 Current Risk Management Liabilities 329 23 1 353 (261 ) 92 Long-term Risk Management Liabilities 208 8 9 225 (94 ) 131 Total Liabilities 537 31 10 578 (355 ) 223 Total MTM Derivative Contract Net Assets (Liabilities) $ 222 $ 2 $ (7 ) $ 217 $ 32 $ 249 (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 and six months ended June 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three and Six Months Ended June 30, 2015 and 2014 Three Months Ended Six Months Ended June 30, June 30, Location of Gain (Loss) 2015 2014 2015 2014 (in millions) Vertically Integrated Utilities Revenues $ 1 $ 4 $ 7 $ 22 Generation & Marketing Revenues 10 16 59 48 Other Operation Expense — — (2 ) — Maintenance Expense — — (1 ) — Purchased Electricity for Resale — — 4 — Regulatory Assets (a) 4 — — — Regulatory Liabilities (a) 49 29 53 118 Total Gain on Risk Management Contracts $ 64 $ 49 $ 120 $ 188 (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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies 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. The following table shows the results of our hedging gains (losses) during the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1 $ 2 $ 6 $ 4 Loss on Fair Value Portion of Long-term Debt (1 ) (2 ) (6 ) (4 ) During the three and six months ended June 30, 2015 and 2014 , hedge ineffectiveness was immaterial. Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows 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 and natural gas designated as cash flow hedges are included in Revenues 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 and six months ended June 30, 2015 and 2014 , we designated power derivatives as cash flow hedges but did not designate 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. The impact of cash flow hedge accounting for these derivative contracts was immaterial and discontinued 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 and six months ended June 30, 2015 and 2014 , 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 and six months ended June 30, 2015 and 2014 , we did not designate any foreign currency derivatives as cash flow hedges. During the three and six months ended June 30, 2015 and 2014 , 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 and six months ended June 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Condensed Balance Sheet June 30, 2015 Commodity Interest Rate Currency Total (in millions) Hedging Assets (a) $ 10 $ — $ 10 Hedging Liabilities (a) 19 1 20 AOCI Loss Net of Tax (5 ) (18 ) (23 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4 (1 ) 3 Impact of Cash Flow Hedges on the Condensed Balance Sheet December 31, 2014 Commodity Interest Rate Total (in millions) Hedging Assets (a) $ 16 $ — $ 16 Hedging Liabilities (a) 14 1 15 AOCI Gain (Loss) Net of Tax 1 (19 ) (18 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4 (2 ) 2 (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 June 30, 2015 , 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 90 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), we are obligated to post an additional amount of collateral for a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads and guaranties for contractual obligations 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 our exposure if our credit ratings were to decline below a specified rating threshold as of June 30, 2015 and December 31, 2014 : June 30, December 31, 2015 2014 (in millions) Fair Value of Contracts with Credit Downgrade Triggers $ — $ — Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement — — Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs 31 36 Amount of Collateral Attributable to Other Contracts (a) 304 281 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contracts. 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 June 30, 2015 and December 31, 2014 : June 30, December 31, (in millions) Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements $ 287 $ 235 Amount of Cash Collateral Posted 5 9 Additional Settlement Liability if Cross Default Provision is Triggered 225 178
Appalachian Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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 June 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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 June 30, 2015 and December 31, 2014 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: June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 52,015 $ — $ — $ 52,015 $ (13,138 ) $ 38,877 Long-term Risk Management Assets 3,286 — — 3,286 (284 ) 3,002 Total Assets 55,301 — — 55,301 (13,422 ) 41,879 Current Risk Management Liabilities 23,210 — — 23,210 (14,051 ) 9,159 Long-term Risk Management Liabilities 1,734 — — 1,734 (286 ) 1,448 Total Liabilities 24,944 — — 24,944 (14,337 ) 10,607 Total MTM Derivative Contract Net Assets (Liabilities) $ 30,357 $ — $ — $ 30,357 $ 915 $ 31,272 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (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. I&M Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 26,147 $ — $ — $ 26,147 $ (9,633 ) $ 16,514 Long-term Risk Management Assets 2,219 — — 2,219 (193 ) 2,026 Total Assets 28,366 — — 28,366 (9,826 ) 18,540 Current Risk Management Liabilities 14,553 — — 14,553 (10,060 ) 4,493 Long-term Risk Management Liabilities 1,176 — — 1,176 (194 ) 982 Total Liabilities 15,729 — — 15,729 (10,254 ) 5,475 Total MTM Derivative Contract Net Assets (Liabilities) $ 12,637 $ — $ — $ 12,637 $ 428 $ 13,065 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (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. OPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 70 $ — $ — $ 70 $ (70 ) $ — Long-term Risk Management Assets 44,056 — — 44,056 — 44,056 Total Assets 44,126 — — 44,126 (70 ) 44,056 Current Risk Management Liabilities 2,201 — — 2,201 (191 ) 2,010 Long-term Risk Management Liabilities 4,573 — — 4,573 — 4,573 Total Liabilities 6,774 — — 6,774 (191 ) 6,583 Total MTM Derivative Contract Net Assets (Liabilities) $ 37,352 $ — $ — $ 37,352 $ 121 $ 37,473 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (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. PSO Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,821 $ — $ — $ 1,821 $ (90 ) $ 1,731 Long-term Risk Management Assets 29 — — 29 — 29 Total Assets 1,850 — — 1,850 (90 ) 1,760 Current Risk Management Liabilities 334 — — 334 (205 ) 129 Long-term Risk Management Liabilities — — — — — — Total Liabilities 334 — — 334 (205 ) 129 Total MTM Derivative Contract Net Assets (Liabilities) $ 1,516 $ — $ — $ 1,516 $ 115 $ 1,631 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (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. SWEPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 2,183 $ — $ — $ 2,183 $ (106 ) $ 2,077 Long-term Risk Management Assets 33 — — 33 — 33 Total Assets 2,216 — — 2,216 (106 ) 2,110 Current Risk Management Liabilities 2,763 — — 2,763 (240 ) 2,523 Long-term Risk Management Liabilities — — — — — — Total Liabilities 2,763 — — 2,763 (240 ) 2,523 Total MTM Derivative Contract Net Assets (Liabilities) $ (547 ) $ — $ — $ (547 ) $ 134 $ (413 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (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 and six months ended June 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. The following table represents the affiliated portion of the Registrant Subsidiaries' assets and liabilities on the condensed balance sheets resulting from these transactions: June 30, 2015 Company Risk Management Assets Regulatory Liabilities and Deferred Investment Tax Credits (in thousands) APCo $ 2,690 $ 2,690 I&M 3,137 3,137 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 designated as cash flow hedges are included in Revenues 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , APCo and I&M designated power 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. The impact of cash flow hedge accounting for these derivative contracts was immaterial and 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , 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 and six months ended June 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and six months ended June 30, 2015 and 2014 , 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 and six months ended June 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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 cred
Indiana Michigan Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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 June 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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 June 30, 2015 and December 31, 2014 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: June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 52,015 $ — $ — $ 52,015 $ (13,138 ) $ 38,877 Long-term Risk Management Assets 3,286 — — 3,286 (284 ) 3,002 Total Assets 55,301 — — 55,301 (13,422 ) 41,879 Current Risk Management Liabilities 23,210 — — 23,210 (14,051 ) 9,159 Long-term Risk Management Liabilities 1,734 — — 1,734 (286 ) 1,448 Total Liabilities 24,944 — — 24,944 (14,337 ) 10,607 Total MTM Derivative Contract Net Assets (Liabilities) $ 30,357 $ — $ — $ 30,357 $ 915 $ 31,272 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (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. I&M Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 26,147 $ — $ — $ 26,147 $ (9,633 ) $ 16,514 Long-term Risk Management Assets 2,219 — — 2,219 (193 ) 2,026 Total Assets 28,366 — — 28,366 (9,826 ) 18,540 Current Risk Management Liabilities 14,553 — — 14,553 (10,060 ) 4,493 Long-term Risk Management Liabilities 1,176 — — 1,176 (194 ) 982 Total Liabilities 15,729 — — 15,729 (10,254 ) 5,475 Total MTM Derivative Contract Net Assets (Liabilities) $ 12,637 $ — $ — $ 12,637 $ 428 $ 13,065 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (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. OPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 70 $ — $ — $ 70 $ (70 ) $ — Long-term Risk Management Assets 44,056 — — 44,056 — 44,056 Total Assets 44,126 — — 44,126 (70 ) 44,056 Current Risk Management Liabilities 2,201 — — 2,201 (191 ) 2,010 Long-term Risk Management Liabilities 4,573 — — 4,573 — 4,573 Total Liabilities 6,774 — — 6,774 (191 ) 6,583 Total MTM Derivative Contract Net Assets (Liabilities) $ 37,352 $ — $ — $ 37,352 $ 121 $ 37,473 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (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. PSO Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,821 $ — $ — $ 1,821 $ (90 ) $ 1,731 Long-term Risk Management Assets 29 — — 29 — 29 Total Assets 1,850 — — 1,850 (90 ) 1,760 Current Risk Management Liabilities 334 — — 334 (205 ) 129 Long-term Risk Management Liabilities — — — — — — Total Liabilities 334 — — 334 (205 ) 129 Total MTM Derivative Contract Net Assets (Liabilities) $ 1,516 $ — $ — $ 1,516 $ 115 $ 1,631 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (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. SWEPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 2,183 $ — $ — $ 2,183 $ (106 ) $ 2,077 Long-term Risk Management Assets 33 — — 33 — 33 Total Assets 2,216 — — 2,216 (106 ) 2,110 Current Risk Management Liabilities 2,763 — — 2,763 (240 ) 2,523 Long-term Risk Management Liabilities — — — — — — Total Liabilities 2,763 — — 2,763 (240 ) 2,523 Total MTM Derivative Contract Net Assets (Liabilities) $ (547 ) $ — $ — $ (547 ) $ 134 $ (413 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (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 and six months ended June 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. The following table represents the affiliated portion of the Registrant Subsidiaries' assets and liabilities on the condensed balance sheets resulting from these transactions: June 30, 2015 Company Risk Management Assets Regulatory Liabilities and Deferred Investment Tax Credits (in thousands) APCo $ 2,690 $ 2,690 I&M 3,137 3,137 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 designated as cash flow hedges are included in Revenues 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , APCo and I&M designated power 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. The impact of cash flow hedge accounting for these derivative contracts was immaterial and 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , 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 and six months ended June 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and six months ended June 30, 2015 and 2014 , 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 and six months ended June 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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 cred
Ohio Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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 June 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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 June 30, 2015 and December 31, 2014 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: June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 52,015 $ — $ — $ 52,015 $ (13,138 ) $ 38,877 Long-term Risk Management Assets 3,286 — — 3,286 (284 ) 3,002 Total Assets 55,301 — — 55,301 (13,422 ) 41,879 Current Risk Management Liabilities 23,210 — — 23,210 (14,051 ) 9,159 Long-term Risk Management Liabilities 1,734 — — 1,734 (286 ) 1,448 Total Liabilities 24,944 — — 24,944 (14,337 ) 10,607 Total MTM Derivative Contract Net Assets (Liabilities) $ 30,357 $ — $ — $ 30,357 $ 915 $ 31,272 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (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. I&M Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 26,147 $ — $ — $ 26,147 $ (9,633 ) $ 16,514 Long-term Risk Management Assets 2,219 — — 2,219 (193 ) 2,026 Total Assets 28,366 — — 28,366 (9,826 ) 18,540 Current Risk Management Liabilities 14,553 — — 14,553 (10,060 ) 4,493 Long-term Risk Management Liabilities 1,176 — — 1,176 (194 ) 982 Total Liabilities 15,729 — — 15,729 (10,254 ) 5,475 Total MTM Derivative Contract Net Assets (Liabilities) $ 12,637 $ — $ — $ 12,637 $ 428 $ 13,065 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (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. OPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 70 $ — $ — $ 70 $ (70 ) $ — Long-term Risk Management Assets 44,056 — — 44,056 — 44,056 Total Assets 44,126 — — 44,126 (70 ) 44,056 Current Risk Management Liabilities 2,201 — — 2,201 (191 ) 2,010 Long-term Risk Management Liabilities 4,573 — — 4,573 — 4,573 Total Liabilities 6,774 — — 6,774 (191 ) 6,583 Total MTM Derivative Contract Net Assets (Liabilities) $ 37,352 $ — $ — $ 37,352 $ 121 $ 37,473 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (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. PSO Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,821 $ — $ — $ 1,821 $ (90 ) $ 1,731 Long-term Risk Management Assets 29 — — 29 — 29 Total Assets 1,850 — — 1,850 (90 ) 1,760 Current Risk Management Liabilities 334 — — 334 (205 ) 129 Long-term Risk Management Liabilities — — — — — — Total Liabilities 334 — — 334 (205 ) 129 Total MTM Derivative Contract Net Assets (Liabilities) $ 1,516 $ — $ — $ 1,516 $ 115 $ 1,631 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (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. SWEPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 2,183 $ — $ — $ 2,183 $ (106 ) $ 2,077 Long-term Risk Management Assets 33 — — 33 — 33 Total Assets 2,216 — — 2,216 (106 ) 2,110 Current Risk Management Liabilities 2,763 — — 2,763 (240 ) 2,523 Long-term Risk Management Liabilities — — — — — — Total Liabilities 2,763 — — 2,763 (240 ) 2,523 Total MTM Derivative Contract Net Assets (Liabilities) $ (547 ) $ — $ — $ (547 ) $ 134 $ (413 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (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 and six months ended June 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. The following table represents the affiliated portion of the Registrant Subsidiaries' assets and liabilities on the condensed balance sheets resulting from these transactions: June 30, 2015 Company Risk Management Assets Regulatory Liabilities and Deferred Investment Tax Credits (in thousands) APCo $ 2,690 $ 2,690 I&M 3,137 3,137 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 designated as cash flow hedges are included in Revenues 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , APCo and I&M designated power 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. The impact of cash flow hedge accounting for these derivative contracts was immaterial and 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , 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 and six months ended June 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and six months ended June 30, 2015 and 2014 , 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 and six months ended June 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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 cred
Public Service Co Of Oklahoma [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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 June 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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 June 30, 2015 and December 31, 2014 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: June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 52,015 $ — $ — $ 52,015 $ (13,138 ) $ 38,877 Long-term Risk Management Assets 3,286 — — 3,286 (284 ) 3,002 Total Assets 55,301 — — 55,301 (13,422 ) 41,879 Current Risk Management Liabilities 23,210 — — 23,210 (14,051 ) 9,159 Long-term Risk Management Liabilities 1,734 — — 1,734 (286 ) 1,448 Total Liabilities 24,944 — — 24,944 (14,337 ) 10,607 Total MTM Derivative Contract Net Assets (Liabilities) $ 30,357 $ — $ — $ 30,357 $ 915 $ 31,272 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (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. I&M Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 26,147 $ — $ — $ 26,147 $ (9,633 ) $ 16,514 Long-term Risk Management Assets 2,219 — — 2,219 (193 ) 2,026 Total Assets 28,366 — — 28,366 (9,826 ) 18,540 Current Risk Management Liabilities 14,553 — — 14,553 (10,060 ) 4,493 Long-term Risk Management Liabilities 1,176 — — 1,176 (194 ) 982 Total Liabilities 15,729 — — 15,729 (10,254 ) 5,475 Total MTM Derivative Contract Net Assets (Liabilities) $ 12,637 $ — $ — $ 12,637 $ 428 $ 13,065 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (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. OPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 70 $ — $ — $ 70 $ (70 ) $ — Long-term Risk Management Assets 44,056 — — 44,056 — 44,056 Total Assets 44,126 — — 44,126 (70 ) 44,056 Current Risk Management Liabilities 2,201 — — 2,201 (191 ) 2,010 Long-term Risk Management Liabilities 4,573 — — 4,573 — 4,573 Total Liabilities 6,774 — — 6,774 (191 ) 6,583 Total MTM Derivative Contract Net Assets (Liabilities) $ 37,352 $ — $ — $ 37,352 $ 121 $ 37,473 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (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. PSO Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,821 $ — $ — $ 1,821 $ (90 ) $ 1,731 Long-term Risk Management Assets 29 — — 29 — 29 Total Assets 1,850 — — 1,850 (90 ) 1,760 Current Risk Management Liabilities 334 — — 334 (205 ) 129 Long-term Risk Management Liabilities — — — — — — Total Liabilities 334 — — 334 (205 ) 129 Total MTM Derivative Contract Net Assets (Liabilities) $ 1,516 $ — $ — $ 1,516 $ 115 $ 1,631 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (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. SWEPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 2,183 $ — $ — $ 2,183 $ (106 ) $ 2,077 Long-term Risk Management Assets 33 — — 33 — 33 Total Assets 2,216 — — 2,216 (106 ) 2,110 Current Risk Management Liabilities 2,763 — — 2,763 (240 ) 2,523 Long-term Risk Management Liabilities — — — — — — Total Liabilities 2,763 — — 2,763 (240 ) 2,523 Total MTM Derivative Contract Net Assets (Liabilities) $ (547 ) $ — $ — $ (547 ) $ 134 $ (413 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (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 and six months ended June 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. The following table represents the affiliated portion of the Registrant Subsidiaries' assets and liabilities on the condensed balance sheets resulting from these transactions: June 30, 2015 Company Risk Management Assets Regulatory Liabilities and Deferred Investment Tax Credits (in thousands) APCo $ 2,690 $ 2,690 I&M 3,137 3,137 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 designated as cash flow hedges are included in Revenues 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , APCo and I&M designated power 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. The impact of cash flow hedge accounting for these derivative contracts was immaterial and 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , 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 and six months ended June 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and six months ended June 30, 2015 and 2014 , 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 and six months ended June 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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 cred
Southwestern Electric Power Co [Member]
Derivatives and Hedging	DERIVATIVES AND HEDGING OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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 June 30, 2015 and December 31, 2014 : Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ — 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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 June 30, 2015 and December 31, 2014 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: June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62 The following tables represent the gross fair value of the Registrant Subsidiaries’ derivative activity on the condensed balance sheets as of June 30, 2015 and December 31, 2014 : APCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 52,015 $ — $ — $ 52,015 $ (13,138 ) $ 38,877 Long-term Risk Management Assets 3,286 — — 3,286 (284 ) 3,002 Total Assets 55,301 — — 55,301 (13,422 ) 41,879 Current Risk Management Liabilities 23,210 — — 23,210 (14,051 ) 9,159 Long-term Risk Management Liabilities 1,734 — — 1,734 (286 ) 1,448 Total Liabilities 24,944 — — 24,944 (14,337 ) 10,607 Total MTM Derivative Contract Net Assets (Liabilities) $ 30,357 $ — $ — $ 30,357 $ 915 $ 31,272 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (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. I&M Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 26,147 $ — $ — $ 26,147 $ (9,633 ) $ 16,514 Long-term Risk Management Assets 2,219 — — 2,219 (193 ) 2,026 Total Assets 28,366 — — 28,366 (9,826 ) 18,540 Current Risk Management Liabilities 14,553 — — 14,553 (10,060 ) 4,493 Long-term Risk Management Liabilities 1,176 — — 1,176 (194 ) 982 Total Liabilities 15,729 — — 15,729 (10,254 ) 5,475 Total MTM Derivative Contract Net Assets (Liabilities) $ 12,637 $ — $ — $ 12,637 $ 428 $ 13,065 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (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. OPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 70 $ — $ — $ 70 $ (70 ) $ — Long-term Risk Management Assets 44,056 — — 44,056 — 44,056 Total Assets 44,126 — — 44,126 (70 ) 44,056 Current Risk Management Liabilities 2,201 — — 2,201 (191 ) 2,010 Long-term Risk Management Liabilities 4,573 — — 4,573 — 4,573 Total Liabilities 6,774 — — 6,774 (191 ) 6,583 Total MTM Derivative Contract Net Assets (Liabilities) $ 37,352 $ — $ — $ 37,352 $ 121 $ 37,473 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (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. PSO Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,821 $ — $ — $ 1,821 $ (90 ) $ 1,731 Long-term Risk Management Assets 29 — — 29 — 29 Total Assets 1,850 — — 1,850 (90 ) 1,760 Current Risk Management Liabilities 334 — — 334 (205 ) 129 Long-term Risk Management Liabilities — — — — — — Total Liabilities 334 — — 334 (205 ) 129 Total MTM Derivative Contract Net Assets (Liabilities) $ 1,516 $ — $ — $ 1,516 $ 115 $ 1,631 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (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. SWEPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 2,183 $ — $ — $ 2,183 $ (106 ) $ 2,077 Long-term Risk Management Assets 33 — — 33 — 33 Total Assets 2,216 — — 2,216 (106 ) 2,110 Current Risk Management Liabilities 2,763 — — 2,763 (240 ) 2,523 Long-term Risk Management Liabilities — — — — — — Total Liabilities 2,763 — — 2,763 (240 ) 2,523 Total MTM Derivative Contract Net Assets (Liabilities) $ (547 ) $ — $ — $ (547 ) $ 134 $ (413 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (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 and six months ended June 30, 2015 and 2014 : Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In connection with OPCo’s June 2012 - May 2015 ESP, the PUCO ordered OPCo to conduct energy and capacity auctions for its entire SSO load for delivery beginning in June 2015, see Note 4 - Rate Matters. These auctions resulted in a range of products, including 12-month, 24-month, and 36-month periods. The delivery period for each contract is scheduled to start on the first day of June of each year, immediately following the auction. Certain affiliated Vertically Integrated Utility and Generation & Marketing segment entities participated in the auction process and were awarded tranches of OPCo’s SSO load. The underlying contracts are derivatives subject to the accounting guidance for “Derivatives and Hedging” and are accounted for using MTM accounting, unless the contract has been designated as a normal purchase or normal sale. The following table represents the affiliated portion of the Registrant Subsidiaries' assets and liabilities on the condensed balance sheets resulting from these transactions: June 30, 2015 Company Risk Management Assets Regulatory Liabilities and Deferred Investment Tax Credits (in thousands) APCo $ 2,690 $ 2,690 I&M 3,137 3,137 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 designated as cash flow hedges are included in Revenues 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate power derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , APCo and I&M designated power 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. The impact of cash flow hedge accounting for these derivative contracts was immaterial and 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 and six months ended June 30, 2015 , the Registrant Subsidiaries did not designate interest rate derivatives as cash flow hedges. During the three and six months ended June 30, 2014 , 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 and six months ended June 30, 2015 and 2014 , the Registrant Subsidiaries did not designate any foreign currency derivatives as cash flow hedges. During the three and six months ended June 30, 2015 and 2014 , 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 and six months ended June 30, 2015 and 2014 , see Note 3 . Cash flow hedges included in Accumulated Other Comprehensive Income (Loss) on the condensed balance sheets as of June 30, 2015 and December 31, 2014 were: Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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 cred

Fair Value Measurements

Fair Value Measurements	6 Months Ended
	Jun. 30, 2015
Fair Value Measurements	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 reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For 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 June 30, 2015 and December 31, 2014 are summarized in the following table: June 30, 2015 December 31, 2014 Book Value Fair Value Book Value Fair Value (in millions) Long-term Debt $ 19,578 $ 21,205 $ 18,684 $ 21,075 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: June 30, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 249 $ — $ — $ 249 Fixed Income Securities – Mutual Funds 81 — — 81 Equity Securities – Mutual Funds 13 13 — 26 Total Other Temporary Investments $ 343 $ 13 $ — $ 356 December 31, 2014 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 280 $ — $ — $ 280 Fixed Income Securities – Mutual Funds 81 — — 81 Equity Securities – Mutual Funds 13 12 — 25 Total Other Temporary Investments $ 374 $ 12 $ — $ 386 (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 and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments — — — 1 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — — As of June 30, 2015 and December 31, 2014 , we had no Other Temporary Investments with an unrealized loss position. As of June 30, 2015 , fixed income securities were primarily debt based mutual funds with short and intermediate maturities. Mutual funds may be sold and do not contain maturity dates. For details of the reasons for changes in Securities Available for Sale included in Accumulated Other Comprehensive Income (Loss) for the three and six months ended June 30, 2015 and 2014 , 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 June 30, 2015 and December 31, 2014 : June 30, 2015 December 31, 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Fair Value Gross Unrealized Gains Other-Than- Temporary (in millions) Cash and Cash Equivalents $ 53 $ — $ — $ 20 $ — $ — Fixed Income Securities: United States Government 786 37 (3 ) 697 45 (5 ) Corporate Debt 62 3 (1 ) 48 4 (1 ) State and Local Government 70 1 — 208 1 — Subtotal Fixed Income Securities 918 41 (4 ) 953 50 (6 ) Equity Securities – Domestic 1,135 595 (78 ) 1,123 599 (79 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106 $ 636 $ (82 ) $ 2,096 $ 649 $ (85 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in millions) Proceeds from Investment Sales $ 288 $ 335 $ 516 $ 483 Purchases of Investments 295 345 541 509 Gross Realized Gains on Investment Sales 8 9 19 17 Gross Realized Losses on Investment Sales 6 8 10 9 The adjusted cost of fixed income securities was $877 million and $903 million as of June 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $540 million and $524 million as of June 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2015 was as follows: Fair Value of Securities (in millions) Within 1 year $ 141 1 year – 5 years 376 5 years – 10 years 186 After 10 years 215 Total $ 918 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 June 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. 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 June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17 $ 6 $ — $ 172 $ 195 Other Temporary Investments Restricted Cash (a) 205 7 — 37 249 Fixed Income Securities - Mutual Funds 81 — — — 81 Equity Securities – Mutual Funds (b) 26 — — — 26 Total Other Temporary Investments 312 7 — 37 356 Risk Management Assets Risk Management Commodity Contracts (c) (d) 23 524 269 (293 ) 523 Cash Flow Hedges: Commodity Hedges (c) — 24 1 (15 ) 10 Fair Value Hedges — — — 2 2 Total Risk Management Assets 23 548 270 (306 ) 535 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 42 — — 11 53 Fixed Income Securities: United States Government — 786 — — 786 Corporate Debt — 62 — — 62 State and Local Government — 70 — — 70 Subtotal Fixed Income Securities — 918 — — 918 Equity Securities – Domestic (b) 1,135 — — — 1,135 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177 918 — 11 2,106 Total Assets $ 1,529 $ 1,479 $ 270 $ (86 ) $ 3,192 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 38 $ 444 $ 62 $ (317 ) $ 227 Cash Flow Hedges: Commodity Hedges (c) — 29 5 (15 ) 19 Interest Rate/Foreign Currency Hedges — 1 — — 1 Fair Value Hedges — 3 — 2 5 Total Risk Management Liabilities $ 38 $ 477 $ 67 $ (330 ) $ 252 Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17 $ 1 $ — $ 145 $ 163 Other Temporary Investments Restricted Cash (a) 234 9 — 37 280 Fixed Income Securities - Mutual Funds 81 — — — 81 Equity Securities – Mutual Funds (b) 25 — — — 25 Total Other Temporary Investments 340 9 — 37 386 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37 528 190 (302 ) 453 Cash Flow Hedges: Commodity Hedges (c) — 32 — (16 ) 16 Fair Value Hedges — 1 — 2 3 Total Risk Management Assets 37 561 190 (316 ) 472 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9 — — 11 20 Fixed Income Securities: United States Government — 697 — — 697 Corporate Debt — 48 — — 48 State and Local Government — 208 — — 208 Subtotal Fixed Income Securities — 953 — — 953 Equity Securities – Domestic (b) 1,123 — — — 1,123 Total Spent Nuclear Fuel and Decommissioning Trusts 1,132 953 — 11 2,096 Total Assets $ 1,526 $ 1,524 $ 190 $ (123 ) $ 3,117 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65 $ 432 $ 36 $ (334 ) $ 199 Cash Flow Hedges: Commodity Hedges (c) — 27 3 (16 ) 14 Interest Rate/Foreign Currency Hedges — 1 — — 1 Fair Value Hedges — 7 — 2 9 Total Risk Management Liabilities $ 65 $ 467 $ 39 $ (348 ) $ 223 (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 June 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($5) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $16 million in 2015 , $53 million in periods 2016-2018, $8 million in periods 2019-2020 and $3 million in periods 2021-2032; Level 3 matures $33 million in 2015 , $59 million in periods 2016-2018, $22 million in periods 2019-2020 and $93 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015 , $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015 , $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts. There were no transfers between Level 1 and Level 2 during the three and six months ended June 30, 2015 and 2014 . 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: Three Months Ended June 30, 2015 Net Risk Management Assets (Liabilities) (in millions) Balance as of March 31, 2015 $ 131 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 12 Purchases, Issuances and Settlements (c) (16 ) Transfers into Level 3 (d) (e) 42 Transfers out of Level 3 (e) (f) (2 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 34 Balance as of June 30, 2015 $ 203 Three Months Ended June 30, 2014 Net Risk Management (in millions) Balance as of March 31, 2014 $ 105 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (14 ) Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 6 Purchases, Issuances and Settlements (c) (2 ) Transfers into Level 3 (d) (e) 5 Transfers out of Level 3 (e) (f) (6 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 38 Balance as of June 30, 2014 $ 132 Six Months Ended June 30, 2015 Net Risk Management (in millions) Balance as of December 31, 2014 $ 151 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 12 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 51 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2 ) Purchases, Issuances and Settlements (c) (54 ) Transfers into Level 3 (d) (e) 21 Transfers out of Level 3 (e) (f) (14 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 38 Balance as of June 30, 2015 $ 203 Six Months Ended June 30, 2014 Net Risk Management (in millions) Balance as of December 31, 2013 $ 117 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 82 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (9 ) Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 14 Purchases, Issuances and Settlements (c) (102 ) Transfers into Level 3 (d) (e) 1 Transfers out of Level 3 (e) (f) (7 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 36 Balance as of June 30, 2014 $ 132 (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 June 30, 2015 and December 31, 2014 : Significant Unobservable Inputs June 30, 2015 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 232 $ 65 Discounted Cash Flow Forward Market Price (a) $ 13.50 $ 163.52 $ 37.79 Counterparty Credit Risk (b) 328 FTRs 38 2 Discounted Cash Flow Forward Market Price (a) (8.00 ) 9.87 1.37 Total $ 270 $ 67 Significant Unobservable Inputs December 31, 2014 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157 $ 37 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33 2 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190 $ 39 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs as of June 30, 2015 : Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Appalachian Power Co [Member]
Fair Value Measurements	FAIR VALUE MEASUREMENTS 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 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 June 30, 2015 and December 31, 2014 are summarized in the following table: June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639 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 June 30, 2015 and December 31, 2014 : June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708 The adjusted cost of fixed income securities was $877 million and $903 million as of June 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $540 million and $524 million as of June 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046 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 June 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 and six months ended June 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 for the Registrant Subsidiaries as of June 30, 2015 and December 31, 2014 : Significant Unobservable Inputs June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of June 30, 2015 : Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Fair Value Measurements	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 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 June 30, 2015 and December 31, 2014 are summarized in the following table: June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639 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 June 30, 2015 and December 31, 2014 : June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708 The adjusted cost of fixed income securities was $877 million and $903 million as of June 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $540 million and $524 million as of June 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046 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 June 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 and six months ended June 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 for the Registrant Subsidiaries as of June 30, 2015 and December 31, 2014 : Significant Unobservable Inputs June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of June 30, 2015 : Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
Ohio Power Co [Member]
Fair Value Measurements	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 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 June 30, 2015 and December 31, 2014 are summarized in the following table: June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639 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 June 30, 2015 and December 31, 2014 : June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708 The adjusted cost of fixed income securities was $877 million and $903 million as of June 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $540 million and $524 million as of June 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046 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 June 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 and six months ended June 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 for the Registrant Subsidiaries as of June 30, 2015 and December 31, 2014 : Significant Unobservable Inputs June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of June 30, 2015 : Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Fair Value Measurements	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 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 June 30, 2015 and December 31, 2014 are summarized in the following table: June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639 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 June 30, 2015 and December 31, 2014 : June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708 The adjusted cost of fixed income securities was $877 million and $903 million as of June 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $540 million and $524 million as of June 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046 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 June 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 and six months ended June 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 for the Registrant Subsidiaries as of June 30, 2015 and December 31, 2014 : Significant Unobservable Inputs June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of June 30, 2015 : Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Fair Value Measurements	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 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 June 30, 2015 and December 31, 2014 are summarized in the following table: June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639 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 June 30, 2015 and December 31, 2014 : June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 ) The following table provides the securities activity within the decommissioning and SNF trusts for the three and six months ended June 30, 2015 and 2014 : Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708 The adjusted cost of fixed income securities was $877 million and $903 million as of June 30, 2015 and December 31, 2014 , respectively. The adjusted cost of equity securities was $540 million and $524 million as of June 30, 2015 and December 31, 2014 , respectively. The fair value of fixed income securities held in the nuclear trust funds, summarized by contractual maturities, as of June 30, 2015 was as follows: Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046 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 June 30, 2015 and December 31, 2014 . As required by the accounting guidance for “Fair Value Measurements and Disclosures,” financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. There have not been any significant changes in management’s valuation techniques. APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 and six months ended June 30, 2015 and 2014 . The following tables set forth a reconciliation of changes in the fair value of net trading derivatives classified as Level 3 in the fair value hierarchy for the Registrant Subsidiaries: Three Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 for the Registrant Subsidiaries as of June 30, 2015 and December 31, 2014 : Significant Unobservable Inputs June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh. The following table provides sensitivity of fair value measurements to increases (decreases) in significant unobservable inputs related to Energy Contracts and FTRs for the Registrant Subsidiaries as of June 30, 2015 : Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)

Income Taxes

Income Taxes	6 Months Ended
	Jun. 30, 2015
Income Taxes	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 We are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in 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. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact net income, cash flows or financial condition.
Appalachian Power Co [Member]
Income Taxes	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 Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the 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 the Registrant Subsidiaries' 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 the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition.
Indiana Michigan Power Co [Member]
Income Taxes	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 Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the 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 the Registrant Subsidiaries' 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 the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition.
Ohio Power Co [Member]
Income Taxes	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 Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the 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 the Registrant Subsidiaries' 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 the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition.
Public Service Co Of Oklahoma [Member]
Income Taxes	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 Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the 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 the Registrant Subsidiaries' 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 the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition.
Southwestern Electric Power Co [Member]
Income Taxes	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 Registrant Subsidiaries are no longer subject to U.S. federal examination for years before 2011. The IRS examination of years 2011, 2012 and 2013 started in April 2014. Although the outcome of tax audits is uncertain, in management’s opinion, adequate provisions for federal income taxes have been made for potential liabilities resulting from such matters. In addition, the 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 the Registrant Subsidiaries' 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 the Registrant Subsidiaries' net income. The Registrant Subsidiaries are no longer subject to state or local income tax examinations by tax authorities for years before 2009. State Tax Legislation House Bill 32 was passed by the state of Texas in June 2015 permanently reducing the Texas income/franchise tax rate from 0.95% to 0.75% effective January 1, 2016, applicable to reports originally due on or after the effective date. The Texas income/franchise tax rate had been scheduled to return to 1% in 2016. The enacted provision did not materially impact the Registrant Subsidiaries' net income, cash flows or financial condition.

Financing Activities

Financing Activities	6 Months Ended
	Jun. 30, 2015
Financing Activities	FINANCING ACTIVITIES Long-term Debt The following table details long-term debt outstanding as of June 30, 2015 and December 31, 2014 : Type of Debt June 30, 2015 December 31, 2014 (in millions) Senior Unsecured Notes $ 13,628 $ 12,647 Pollution Control Bonds 1,963 1,963 Notes Payable 409 357 Securitization Bonds 2,200 2,380 Spent Nuclear Fuel Obligation (a) 266 266 Other Long-term Debt 1,144 1,101 Fair Value of Interest Rate Hedges (3 ) (6 ) Unamortized Discount, Net (29 ) (24 ) Total Long-term Debt Outstanding 19,578 18,684 Long-term Debt Due Within One Year 1,817 2,503 Long-term Debt $ 17,761 $ 16,181 (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 June 30, 2015 and December 31, 2014 , 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 six months of 2015 are shown in the tables below: Company Type of Debt Principal Amount Interest Rate Due Date Issuances: (in millions) (%) APCo Pollution Control Bonds $ 86 1.90 2019 APCo Senior Unsecured Notes 350 4.45 2045 APCo Senior Unsecured Notes 300 3.40 2025 I&M Notes Payable 111 Variable 2019 I&M Other Long-term Debt 100 Variable 2018 PSO Senior Unsecured Notes 125 3.17 2025 PSO Senior Unsecured Notes 125 4.09 2045 SWEPCo Pollution Control Bonds 54 1.60 2019 SWEPCo Senior Unsecured Notes 400 3.90 2045 Non-Registrant: AEPTCo Senior Unsecured Notes 60 4.01 2030 AEPTCo Senior Unsecured Notes 50 3.66 2025 AEPTCo Senior Unsecured Notes 40 3.76 2025 AGR Other Long-term Debt 500 Variable 2017 KPCo Other Long-term Debt 25 Variable 2018 Transource Missouri Other Long-term Debt 13 Variable 2018 WPCo Senior Unsecured Notes 113 3.36 2022 WPCo Senior Unsecured Notes 122 3.70 2025 WPCo Senior Unsecured Notes 50 4.20 2035 Total Issuances $ 2,624 (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 issuance amount. Company Type of Debt Principal Amount Paid Interest Due Date Total Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11 2.008 2024 APCo Senior Unsecured Notes 350 7.95 2020 APCo Senior Unsecured Notes 300 3.40 2015 I&M Other Long-term Debt 94 Variable 2015 I&M Notes Payable 18 Variable 2016 I&M Notes Payable 14 Variable 2017 I&M Notes Payable 16 Variable 2019 I&M Notes Payable 6 Variable 2019 I&M Notes Payable 1 Variable 2016 I&M Notes Payable 1 2.12 2016 OPCo Pollution Control Bonds 86 3.125 2015 OPCo Securitization Bonds 22 0.958 2018 SWEPCo Notes Payable 2 4.58 2032 SWEPCo Pollution Control Bonds 54 3.25 2015 SWEPCo Senior Unsecured Notes 100 5.375 2015 Non-Registrant: AEGCo Senior Unsecured Notes 4 6.33 2037 AEP Subsidiaries Notes Payable 1 Variable 2017 AGR Other Long-term Debt 500 Variable 2015 TCC Securitization Bonds 78 5.09 2015 TCC Securitization Bonds 42 6.25 2016 TCC Securitization Bonds 27 0.88 2017 Total Retirements and Principal Payments $ 1,727 In July 2015, OPCo retired $23 million of Securitization Bonds. In July 2015, SWEPCo retired $150 million of 4.9% Senior Unsecured Notes due in 2015 . In July 2015, TCC retired $94 million of Securitization Bonds. As of June 30, 2015 , trustees held on our behalf, $385 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: June 30, 2015 December 31, 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 708 0.27 % $ 744 0.22 % Commercial Paper 397 0.47 % 602 0.59 % Total Short-term Debt $ 1,105 $ 1,346 (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 $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. Accounts receivable information for AEP Credit is as follows: Three Months Ended Six Months Ended 2015 2014 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.27 % 0.22 % 0.27 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 6 $ 7 $ 13 $ 14 June 30, 2015 December 31, 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 977 $ 975 Total Principal Outstanding 708 744 Delinquent Securitized Accounts Receivable 50 44 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 19 13 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 363 335 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	FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first six months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 In July 2015, OPCo retired $23 million of Securitization Bonds. In July 2015, SWEPCo retired $150 million of 4.9% Senior Unsecured Notes due in 2015. As of June 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 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. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo 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. 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 June 30, 2015 and December 31, 2014 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 six months ended June 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — % 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 $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2015 and December 31, 2014 was as follows: June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497
Indiana Michigan Power Co [Member]
Financing Activities	FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first six months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 In July 2015, OPCo retired $23 million of Securitization Bonds. In July 2015, SWEPCo retired $150 million of 4.9% Senior Unsecured Notes due in 2015. As of June 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 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. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo 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. 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 June 30, 2015 and December 31, 2014 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 six months ended June 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — % 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 $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2015 and December 31, 2014 was as follows: June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497
Ohio Power Co [Member]
Financing Activities	FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first six months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 In July 2015, OPCo retired $23 million of Securitization Bonds. In July 2015, SWEPCo retired $150 million of 4.9% Senior Unsecured Notes due in 2015. As of June 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 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. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo 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. 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 June 30, 2015 and December 31, 2014 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 six months ended June 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — % 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 $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2015 and December 31, 2014 was as follows: June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497
Public Service Co Of Oklahoma [Member]
Financing Activities	FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first six months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 In July 2015, OPCo retired $23 million of Securitization Bonds. In July 2015, SWEPCo retired $150 million of 4.9% Senior Unsecured Notes due in 2015. As of June 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 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. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo 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. 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 June 30, 2015 and December 31, 2014 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 six months ended June 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — % 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 $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2015 and December 31, 2014 was as follows: June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497
Southwestern Electric Power Co [Member]
Financing Activities	FINANCING ACTIVITIES Long-term Debt Long-term debt and other securities issued, retired and principal payments made during the first six months of 2015 are shown in the tables below: Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts. Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015 In July 2015, OPCo retired $23 million of Securitization Bonds. In July 2015, SWEPCo retired $150 million of 4.9% Senior Unsecured Notes due in 2015. As of June 30, 2015 , trustees held on behalf of I&M and OPCo, $40 million and $345 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. This restriction does not limit the ability of the Registrant Subsidiaries to pay dividends out of retained earnings. Additionally, the Federal Power Act creates a reserve on earnings attributable to hydroelectric generation plants. Because of their respective ownership of such plants, this reserve applies to APCo and I&M. Leverage Restrictions Pursuant to the credit agreement leverage restrictions, APCo, I&M, PSO and SWEPCo 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. 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 June 30, 2015 and December 31, 2014 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 six months ended June 30, 2015 are described in the following table: Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000 The maximum and minimum interest rates for funds either borrowed from or loaned to the Utility Money Pool were as follows: Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 % The average interest rates for funds borrowed from and loaned to the Utility Money Pool for the six months ended June 30, 2015 and 2014 are summarized for all Registrant Subsidiaries in the following table: Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — % 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 $750 million from bank conduits to purchase receivables. The agreement was increased in June 2014 from $700 million and expires in June 2017. The amount of accounts receivable and accrued unbilled revenues under the sale of receivables agreement for each Registrant Subsidiary as of June 30, 2015 and December 31, 2014 was as follows: June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668 The fees paid by the Registrant Subsidiaries to AEP Credit for customer accounts receivable sold were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145 The Registrant Subsidiaries’ proceeds on the sale of receivables to AEP Credit were: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497

Variable Interest Entities

Variable Interest Entities	6 Months Ended
	Jun. 30, 2015
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. 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 any of these entities 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 June 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the six months ended June 30, 2015 and 2014 were $83 million and $80 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, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2015 and 2014 were $34 million and $32 million , respectively, and for the six months ended June 30, 2015 and 2014 were $57 million and $56 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. 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 Receivable – 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 $1.6 billion and $1.8 billion as of June 30, 2015 and December 31, 2014 , respectively. Transition Funding has securitized transition assets of $1.5 billion and $1.6 billion as of June 30, 2015 and December 31, 2014 , 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 $210 million and $232 million as of June 30, 2015 and December 31, 2014 , respectively. Ohio Phase-in-Recovery Funding has securitized assets of $98 million and $110 million as of June 30, 2015 and December 31, 2014 , 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 $357 million and $368 million as of June 30, 2015 and December 31, 2014 , respectively. Appalachian Consumer Rate Relief Funding has securitized assets of $339 million and $350 million as of June 30, 2015 and December 31, 2014 , 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 tables 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 of EIS, management concluded that we are the primary beneficiary of the protected cell and are required to consolidate the protected cell of EIS. Our insurance premium expense to the protected cell for the three months ended June 30, 2015 and 2014 was $0.2 million and $1.4 million , respectively, and for the six months ended June 30, 2015 and 2014 was $14 million and $18 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. Therefore, AEP is required to consolidate Transource Energy. AEP’s equity interest could potentially be significant. In January 2014, Transource Missouri (a wholly-owned subsidiary of Transource Energy) acquired transmission assets from the non-controlling owner and issued debt and received a capital contribution to fund the acquisition. The majority of Transource Energy’s activity resulted from the asset acquisition, construction projects, debt issuance and capital contribution. AEP provided capital contributions to Transource Energy of $17 million and $23 million during the six months ended June 30, 2015 and the year ended December 31, 2014 , respectively. AEP and the other owner of Transource Energy are required to ensure a specific equity level in Transource Missouri upon completion of projects or if a project is abandoned by the RTO. See the tables below for the classification of Transource Energy’s assets and liabilities on the 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 June 30, 2015 (in millions) SWEPCo Sabine I&M DCC Fuel AEP Credit TCC Transition Funding OPCo Ohio Phase-in- Recovery Funding APCo Appalachian Consumer Rate Relief Funding Protected Cell of EIS Transource Energy ASSETS Current Assets $ 58 $ 114 $ 986 $ 220 $ 33 $ 19 $ 155 $ 10 Net Property, Plant and Equipment 142 220 — — — — — 137 Other Noncurrent Assets 60 118 — 1,533 (a) 186 (b) 347 (c) 1 5 Total Assets $ 260 $ 452 $ 986 $ 1,753 $ 219 $ 366 $ 156 $ 152 LIABILITIES AND EQUITY Current Liabilities $ 28 $ 109 $ 886 $ 326 $ 47 $ 27 $ 43 $ 28 Noncurrent Liabilities 232 343 — 1,409 171 337 67 70 Equity — — 100 18 1 2 46 54 Total Liabilities and Equity $ 260 $ 452 $ 986 $ 1,753 $ 219 $ 366 $ 156 $ 152 (a) Includes an intercompany item eliminated in consolidation of $72 million . (b) Includes an intercompany item eliminated in consolidation of $87 million . (c) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 (in millions) SWEPCo Sabine I&M DCC Fuel AEP Credit TCC Transition Funding OPCo Ohio Phase-in- Recovery Funding APCo Appalachian Consumer Rate Relief Funding Protected Cell of EIS Transource Energy ASSETS Current Assets $ 68 $ 97 $ 980 $ 239 $ 33 $ 18 $ 149 $ 2 Net Property, Plant and Equipment 145 158 — — — — — 98 Other Noncurrent Assets 52 80 — 1,654 (a) 210 (b) 358 (c) 2 4 Total Assets $ 265 $ 335 $ 980 $ 1,893 $ 243 $ 376 $ 151 $ 104 LIABILITIES AND EQUITY Current Liabilities $ 36 $ 86 $ 894 $ 322 $ 47 $ 27 $ 44 $ 21 Noncurrent Liabilities 228 249 — 1,553 195 347 62 55 Equity 1 — 86 18 1 2 45 28 Total Liabilities and Equity $ 265 $ 335 $ 980 $ 1,893 $ 243 $ 376 $ 151 $ 104 (a) Includes an intercompany item eliminated in consolidation of $75 million . (b) Includes an intercompany item eliminated in consolidation of $97 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 June 30, 2015 and 2014 were $15 million and $6 million , respectively, and for the six months ended June 30, 2015 and 2014 were $29 million and $8 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: June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from SWEPCo $ 8 $ 8 $ 8 $ 8 Retained Earnings 6 6 4 4 Advance Due to Parent 56 56 56 56 Guarantee of Debt — 50 — 48 Total Investment in DHLC $ 70 $ 120 $ 68 $ 116 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 and controlled by a subsidiary of FirstEnergy. Provisions exist within the PATH-WV agreement that make it 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, the transmission project that PATH was intended to develop, and removed it from the 2012 Regional Transmission Expansion Plan. In September 2012, the PATH Project companies submitted an application to the FERC requesting authority to recover prudently-incurred costs associated with the PATH Project. In November 2012, the FERC issued an order accepting the PATH Project's abandonment cost recovery application, subject to settlement procedures and hearing. The parties to the case have been unable to reach a settlement agreement and in March 2014, settlement judge procedures were terminated. Hearings at FERC were held in March and April 2015. Our investment in PATH-WV was: June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 19 $ 19 $ 19 $ 19 Retained Earnings 2 2 2 2 Total Investment in PATH-WV $ 21 $ 21 $ 21 $ 21 As of June 30, 2015 , our $21 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	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. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds 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 June 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the six months ended June 30, 2015 and 2014 were $83 million and $80 million , respectively. See the table 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 June 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 57,592 $ 67,981 Net Property, Plant and Equipment 142,265 145,491 Other Noncurrent Assets 59,717 51,578 Total Assets $ 259,574 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 28,122 $ 36,286 Noncurrent Liabilities 231,155 228,349 Equity 297 415 Total Liabilities and Equity $ 259,574 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2015 and 2014 were $34 million and $32 million , respectively, and for the six months ended June 30, 2015 and 2014 were $57 million and $56 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s 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 June 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 114,522 $ 97,361 Net Property, Plant and Equipment 219,786 158,121 Other Noncurrent Assets 117,702 79,705 Total Assets $ 452,010 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 109,491 $ 86,026 Noncurrent Liabilities 342,519 249,161 Total Liabilities and Equity $ 452,010 $ 335,187 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 $210 million and $232 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long-term debt on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $98 million and $110 million as of June 30, 2015 and December 31, 2014 , 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. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 32,778 $ 32,676 Other Noncurrent Assets (a) 186,609 209,922 Total Assets $ 219,387 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 47,539 $ 47,099 Noncurrent Liabilities 170,511 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 219,387 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $87 million and $97 million , respectively. 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 $357 million and $368 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long term debt on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $339 million and $350 million as of June 30, 2015 and December 31, 2014 , 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 West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 19,145 $ 18,099 Other Noncurrent Assets (a) 346,809 358,264 Total Assets $ 365,954 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 26,912 $ 26,809 Noncurrent Liabilities 337,316 347,652 Equity 1,726 1,902 Total Liabilities and Equity $ 365,954 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. 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 June 30, 2015 and 2014 were $15 million and $6 million , respectively, and for the six months ended June 30, 2015 and 2014 were $29 million and $8 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: June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,540 5,540 3,819 3,819 SWEPCo's Guarantee of Debt — 106,408 (a) — 104,334 (a) Total Investment in DHLC $ 13,183 $ 119,591 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $56 million and $56 million in 2015 and 2014 , 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 June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772 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 13 in the 2014 Annual Report. Total billings from AEGCo were as follows: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) I&M $ 59,993 $ 65,190 $ 114,958 $ 135,612 The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) I&M $ 21,084 $ 21,084 $ 20,031 $ 20,031
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. 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. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds 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 June 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the six months ended June 30, 2015 and 2014 were $83 million and $80 million , respectively. See the table 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 June 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 57,592 $ 67,981 Net Property, Plant and Equipment 142,265 145,491 Other Noncurrent Assets 59,717 51,578 Total Assets $ 259,574 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 28,122 $ 36,286 Noncurrent Liabilities 231,155 228,349 Equity 297 415 Total Liabilities and Equity $ 259,574 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2015 and 2014 were $34 million and $32 million , respectively, and for the six months ended June 30, 2015 and 2014 were $57 million and $56 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s 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 June 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 114,522 $ 97,361 Net Property, Plant and Equipment 219,786 158,121 Other Noncurrent Assets 117,702 79,705 Total Assets $ 452,010 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 109,491 $ 86,026 Noncurrent Liabilities 342,519 249,161 Total Liabilities and Equity $ 452,010 $ 335,187 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 $210 million and $232 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long-term debt on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $98 million and $110 million as of June 30, 2015 and December 31, 2014 , 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. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 32,778 $ 32,676 Other Noncurrent Assets (a) 186,609 209,922 Total Assets $ 219,387 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 47,539 $ 47,099 Noncurrent Liabilities 170,511 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 219,387 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $87 million and $97 million , respectively. 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 $357 million and $368 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long term debt on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $339 million and $350 million as of June 30, 2015 and December 31, 2014 , 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 West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 19,145 $ 18,099 Other Noncurrent Assets (a) 346,809 358,264 Total Assets $ 365,954 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 26,912 $ 26,809 Noncurrent Liabilities 337,316 347,652 Equity 1,726 1,902 Total Liabilities and Equity $ 365,954 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. 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 June 30, 2015 and 2014 were $15 million and $6 million , respectively, and for the six months ended June 30, 2015 and 2014 were $29 million and $8 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: June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,540 5,540 3,819 3,819 SWEPCo's Guarantee of Debt — 106,408 (a) — 104,334 (a) Total Investment in DHLC $ 13,183 $ 119,591 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $56 million and $56 million in 2015 and 2014 , 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 June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772 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 13 in the 2014 Annual Report. Total billings from AEGCo were as follows: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) I&M $ 59,993 $ 65,190 $ 114,958 $ 135,612 The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) I&M $ 21,084 $ 21,084 $ 20,031 $ 20,031
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. 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. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds 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 June 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the six months ended June 30, 2015 and 2014 were $83 million and $80 million , respectively. See the table 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 June 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 57,592 $ 67,981 Net Property, Plant and Equipment 142,265 145,491 Other Noncurrent Assets 59,717 51,578 Total Assets $ 259,574 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 28,122 $ 36,286 Noncurrent Liabilities 231,155 228,349 Equity 297 415 Total Liabilities and Equity $ 259,574 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2015 and 2014 were $34 million and $32 million , respectively, and for the six months ended June 30, 2015 and 2014 were $57 million and $56 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s 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 June 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 114,522 $ 97,361 Net Property, Plant and Equipment 219,786 158,121 Other Noncurrent Assets 117,702 79,705 Total Assets $ 452,010 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 109,491 $ 86,026 Noncurrent Liabilities 342,519 249,161 Total Liabilities and Equity $ 452,010 $ 335,187 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 $210 million and $232 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long-term debt on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $98 million and $110 million as of June 30, 2015 and December 31, 2014 , 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. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 32,778 $ 32,676 Other Noncurrent Assets (a) 186,609 209,922 Total Assets $ 219,387 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 47,539 $ 47,099 Noncurrent Liabilities 170,511 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 219,387 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $87 million and $97 million , respectively. 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 $357 million and $368 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long term debt on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $339 million and $350 million as of June 30, 2015 and December 31, 2014 , 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 West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 19,145 $ 18,099 Other Noncurrent Assets (a) 346,809 358,264 Total Assets $ 365,954 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 26,912 $ 26,809 Noncurrent Liabilities 337,316 347,652 Equity 1,726 1,902 Total Liabilities and Equity $ 365,954 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. 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 June 30, 2015 and 2014 were $15 million and $6 million , respectively, and for the six months ended June 30, 2015 and 2014 were $29 million and $8 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: June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,540 5,540 3,819 3,819 SWEPCo's Guarantee of Debt — 106,408 (a) — 104,334 (a) Total Investment in DHLC $ 13,183 $ 119,591 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $56 million and $56 million in 2015 and 2014 , 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 June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772 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 13 in the 2014 Annual Report. Total billings from AEGCo were as follows: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) I&M $ 59,993 $ 65,190 $ 114,958 $ 135,612 The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) I&M $ 21,084 $ 21,084 $ 20,031 $ 20,031
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. 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. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds 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 June 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the six months ended June 30, 2015 and 2014 were $83 million and $80 million , respectively. See the table 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 June 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 57,592 $ 67,981 Net Property, Plant and Equipment 142,265 145,491 Other Noncurrent Assets 59,717 51,578 Total Assets $ 259,574 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 28,122 $ 36,286 Noncurrent Liabilities 231,155 228,349 Equity 297 415 Total Liabilities and Equity $ 259,574 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2015 and 2014 were $34 million and $32 million , respectively, and for the six months ended June 30, 2015 and 2014 were $57 million and $56 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s 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 June 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 114,522 $ 97,361 Net Property, Plant and Equipment 219,786 158,121 Other Noncurrent Assets 117,702 79,705 Total Assets $ 452,010 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 109,491 $ 86,026 Noncurrent Liabilities 342,519 249,161 Total Liabilities and Equity $ 452,010 $ 335,187 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 $210 million and $232 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long-term debt on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $98 million and $110 million as of June 30, 2015 and December 31, 2014 , 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. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 32,778 $ 32,676 Other Noncurrent Assets (a) 186,609 209,922 Total Assets $ 219,387 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 47,539 $ 47,099 Noncurrent Liabilities 170,511 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 219,387 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $87 million and $97 million , respectively. 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 $357 million and $368 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long term debt on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $339 million and $350 million as of June 30, 2015 and December 31, 2014 , 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 West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 19,145 $ 18,099 Other Noncurrent Assets (a) 346,809 358,264 Total Assets $ 365,954 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 26,912 $ 26,809 Noncurrent Liabilities 337,316 347,652 Equity 1,726 1,902 Total Liabilities and Equity $ 365,954 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. 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 June 30, 2015 and 2014 were $15 million and $6 million , respectively, and for the six months ended June 30, 2015 and 2014 were $29 million and $8 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: June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,540 5,540 3,819 3,819 SWEPCo's Guarantee of Debt — 106,408 (a) — 104,334 (a) Total Investment in DHLC $ 13,183 $ 119,591 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $56 million and $56 million in 2015 and 2014 , 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 June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772 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 13 in the 2014 Annual Report. Total billings from AEGCo were as follows: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) I&M $ 59,993 $ 65,190 $ 114,958 $ 135,612 The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) I&M $ 21,084 $ 21,084 $ 20,031 $ 20,031
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. 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. In addition, the Registrant Subsidiaries have not provided material financial or other support to any of these entities that was not previously contractually required. SWEPCo holds a significant variable interest in DHLC. Each of the Registrant Subsidiaries hold a significant variable interest in AEPSC. I&M holds 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 June 30, 2015 and 2014 were $41 million and $41 million , respectively, and for the six months ended June 30, 2015 and 2014 were $83 million and $80 million , respectively. See the table 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 June 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 57,592 $ 67,981 Net Property, Plant and Equipment 142,265 145,491 Other Noncurrent Assets 59,717 51,578 Total Assets $ 259,574 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 28,122 $ 36,286 Noncurrent Liabilities 231,155 228,349 Equity 297 415 Total Liabilities and Equity $ 259,574 $ 265,050 I&M has nuclear fuel lease agreements with DCC Fuel, which was formed for the purpose of acquiring, owning and leasing nuclear fuel to I&M. DCC Fuel purchased the nuclear fuel from I&M with funds received from the issuance of notes to financial institutions. Each DCC Fuel entity is a single-lessee leasing arrangement with only one asset and is capitalized with all debt. Each is a separate legal entity from I&M, the assets of which are not available to satisfy the debts of I&M. Payments on the leases for the three months ended June 30, 2015 and 2014 were $34 million and $32 million , respectively, and for the six months ended June 30, 2015 and 2014 were $57 million and $56 million , respectively. The leases were recorded as capital leases on I&M’s balance sheet as title to the nuclear fuel transfers to I&M at the end of the respective lease terms, which do not exceed 54 months . Based on I&M’s control of DCC Fuel, management concluded that I&M is the primary beneficiary and is required to consolidate DCC Fuel. The capital leases are eliminated upon consolidation. See the table below for the classification of DCC Fuel’s assets and liabilities on I&M’s 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 June 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 114,522 $ 97,361 Net Property, Plant and Equipment 219,786 158,121 Other Noncurrent Assets 117,702 79,705 Total Assets $ 452,010 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 109,491 $ 86,026 Noncurrent Liabilities 342,519 249,161 Total Liabilities and Equity $ 452,010 $ 335,187 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 $210 million and $232 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long-term debt on the condensed balance sheets. Ohio Phase-in-Recovery Funding has securitized assets of $98 million and $110 million as of June 30, 2015 and December 31, 2014 , 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. See the table below for the classification of Ohio Phase-in-Recovery Funding’s assets and liabilities on OPCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 32,778 $ 32,676 Other Noncurrent Assets (a) 186,609 209,922 Total Assets $ 219,387 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 47,539 $ 47,099 Noncurrent Liabilities 170,511 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 219,387 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $87 million and $97 million , respectively. 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 $357 million and $368 million as of June 30, 2015 and December 31, 2014 , respectively, and are included in current and long term debt on the condensed balance sheets. Appalachian Consumer Rate Relief Funding has securitized assets of $339 million and $350 million as of June 30, 2015 and December 31, 2014 , 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 West Virginia deferred generation charges from customers receiving electric transmission, distribution and generation service from APCo under a recovery mechanism approved by the WVPSC. In November 2013, securitization bonds were issued. The securitization bonds are payable only from and secured by the securitized assets. The bondholders have no recourse to APCo or any other AEP entity. APCo acts as the servicer for Appalachian Consumer Rate Relief Funding's securitized assets and remits all related amounts collected from customers to Appalachian Consumer Rate Relief Funding for interest and principal payments on the securitization bonds and related costs. See the table below for the classification of Appalachian Consumer Rate Relief Funding’s assets and liabilities on APCo’s condensed balance sheets. 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 June 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 19,145 $ 18,099 Other Noncurrent Assets (a) 346,809 358,264 Total Assets $ 365,954 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 26,912 $ 26,809 Noncurrent Liabilities 337,316 347,652 Equity 1,726 1,902 Total Liabilities and Equity $ 365,954 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively. 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 June 30, 2015 and 2014 were $15 million and $6 million , respectively, and for the six months ended June 30, 2015 and 2014 were $29 million and $8 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: June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,540 5,540 3,819 3,819 SWEPCo's Guarantee of Debt — 106,408 (a) — 104,334 (a) Total Investment in DHLC $ 13,183 $ 119,591 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $56 million and $56 million in 2015 and 2014 , 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 June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741 The carrying amount and classification of variable interest in AEPSC’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772 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 13 in the 2014 Annual Report. Total billings from AEGCo were as follows: Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) I&M $ 59,993 $ 65,190 $ 114,958 $ 135,612 The carrying amount and classification of variable interest in AEGCo’s accounts payable are as follows: June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) I&M $ 21,084 $ 21,084 $ 20,031 $ 20,031

Disposition Plant Severance

Disposition Plant Severance	6 Months Ended
	Jun. 30, 2015
Cost Reduction Programs	14 . DISPOSITION PLANT SEVERANCE AEP retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The disposition plant severance activity for the six months ended June 30, 2015 is described in the following table: Disposition Plant Severance Activity (in millions) Balance as of December 31, 2014 $ 29 Incurred 3 Settled (11 ) Adjustments — Balance as of June 30, 2015 $ 21 We recorded a charge of $29 million to Other Operation expense in 2014 primarily related to employees at the disposition plants. These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. Of the cumulative expense, approximately 32% was within the Generation & Marketing segment and 68% was within the Vertically Integrated Utilities segment. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. We incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. We do not expect additional severance costs to be incurred related to this initiative.
Appalachian Power Co [Member]
Cost Reduction Programs	14 . DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the six months ended June 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative.
Indiana Michigan Power Co [Member]
Cost Reduction Programs	14 . DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the six months ended June 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative.
Ohio Power Co [Member]
Cost Reduction Programs	14 . DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the six months ended June 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative.
Public Service Co Of Oklahoma [Member]
Cost Reduction Programs	14 . DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the six months ended June 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative.
Southwestern Electric Power Co [Member]
Cost Reduction Programs	14 . DISPOSITION PLANT SEVERANCE Management retired several generation plants or units of plants during 2015. These plant closures resulted in involuntary severances. The severance program provides two weeks of base pay for every year of service along with other severance benefits. The Registrant Subsidiaries' disposition plant severance activity for the six months ended June 30, 2015 is described in the following table: Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant. The Registrant Subsidiaries recorded charges to Other Operation expense in 2014 primarily related to employees at the disposition plants. The total amount incurred in 2014 by Registrant Subsidiary was as follows: Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289 These expenses, net of adjustments, relate primarily to severance benefits and are included primarily in Other Operation expense on the condensed statements of income. The remaining liability is included in Other Current Liabilities on the condensed balance sheets. The Registrant Subsidiaries incurred additional charges during the second quarter of 2015 as severance plans were finalized after the plants were retired. Management does not expect additional severance costs to be incurred related to this initiative.

Property, Plant and Equipment P

Property, Plant and Equipment Property, Plant and Equipment	6 Months Ended
	Jun. 30, 2015
Property, Plant and Equipment Disclosure [Text Block]	13 . PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant. We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. We do not estimate the retirement for such easements because we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected. We recorded an increase in our asset retirement obligations in the second quarter of 2015 , primarily related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the aggregate carrying amount of ARO: Carrying Amount of ARO (in millions) ARO as of December 31, 2014 $ 2,019 Accretion Expense 50 Liabilities Incurred 47 Liabilities Settled (22 ) Revisions in Cash Flow Estimates 48 ARO as of June 30, 2015 $ 2,142 As of June 30, 2015 and December 31, 2014 , our ARO liability included $1.3 billion and $1.3 billion , respectively, for nuclear decommissioning of the Cook Plant. As of June 30, 2015 and December 31, 2014 , the fair value of assets that are legally restricted for purposes of settling the nuclear decommissioning liabilities totaled $1.8 billion and $1.8 billion , respectively, and are recorded in Spent Nuclear Fuel and Decommissioning Trusts on the condensed balance sheets.
Appalachian Power Co [Member]
Property, Plant and Equipment Disclosure [Text Block]	PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of June 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.3 billion and $1.3 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of June 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.8 billion and $1.8 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015 , partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.
Indiana Michigan Power Co [Member]
Property, Plant and Equipment Disclosure [Text Block]	PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of June 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.3 billion and $1.3 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of June 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.8 billion and $1.8 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015 , partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.
Ohio Power Co [Member]
Property, Plant and Equipment Disclosure [Text Block]	PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of June 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.3 billion and $1.3 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of June 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.8 billion and $1.8 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015 , partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.
Public Service Co Of Oklahoma [Member]
Property, Plant and Equipment Disclosure [Text Block]	PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of June 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.3 billion and $1.3 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of June 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.8 billion and $1.8 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015 , partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.
Southwestern Electric Power Co [Member]
Property, Plant and Equipment Disclosure [Text Block]	PROPERTY, PLANT AND EQUIPMENT Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected. As of June 30, 2015 and December 31, 2014 , I&M's ARO liability for nuclear decommissioning of the Cook Plant was $1.3 billion and $1.3 billion , respectively. These liabilities are reflected in Asset Retirement Obligations on I&M's condensed balance sheets. As of June 30, 2015 and December 31, 2014 , the fair value of I&M's assets that are legally restricted for purposes of settling decommissioning liabilities totaled $1.8 billion and $1.8 billion , respectively. These assets are included in Spent Nuclear Fuel and Decommissioning Trusts on I&M's condensed balance sheets. The Registrant Subsidiaries recorded an increase in asset retirement obligations in the second quarter of 2015 , partially related to the final Coal Combustion Residual Rule, which was published in the Federal Register in April 2015. The Federal EPA now regulates the disposal and beneficial re-use of coal combustion residuals (CCR), including fly ash and bottom ash generated at coal-fired electric generating units and also FGD gypsum generated at some coal-fired plants. The Federal EPA regulates CCR as a non-hazardous solid waste and established minimum federal solid waste management standards. Noncash increases related to the CCR Rule are recorded as Property, Plant and Equipment. The following is a reconciliation of the 2015 and 2014 aggregate carrying amounts of ARO by Registrant Subsidiary: ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.

Significant Accounting Matters

Significant Accounting Matters (Policies)	6 Months Ended
	Jun. 30, 2015
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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2014 consolidated financial statements and notes thereto, which are included in our Form 10-K as filed with the SEC on February 20, 2015 .
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, KPCo and WPCo 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 on January 1, 2014, 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 EPS is calculated by dividing net earnings available to common shareholders by the weighted average number of common shares outstanding during the period. Diluted EPS is calculated by adjusting the weighted average outstanding common shares, assuming conversion of all potentially dilutive stock options and awards.
Appalachian Power Co [Member]
Basis of Accounting	General The unaudited condensed financial statements and footnotes were prepared in accordance with GAAP for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the SEC. Accordingly, they do not include all of the information and footnotes required by GAAP for complete annual financial statements. In the opinion of management, the unaudited condensed interim financial statements reflect all normal and recurring accruals and adjustments necessary for a fair presentation of the net income, financial position and cash flows for the interim periods for each Registrant Subsidiary. Net income for the three and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .
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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .
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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .
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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .
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 and six months ended June 30, 2015 is not necessarily indicative of results that may be expected for the year ending December 31, 2015 . The condensed financial statements are unaudited and should be read in conjunction with the audited 2014 financial statements and notes thereto, which are included in the Registrant Subsidiaries’ Annual Reports on Form 10-K as filed with the SEC on February 20, 2015 .

Derivatives and Hedging (Polici

Derivatives and Hedging (Policies)	6 Months Ended
	Jun. 30, 2015
Derivatives and Hedging	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), we are obligated to post an additional amount of collateral for a limited number of derivative and non-derivative contracts primarily related to our competitive retail auction loads and guaranties for contractual obligations 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. 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 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. In March 2014, these contracts were 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. 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. 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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Fair Value Hedging Strategies 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. 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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS We are exposed to certain market risks as a major power producer and participant in the wholesale electricity, natural gas, coal and emission allowance markets. 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. 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. 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 and natural gas designated as cash flow hedges are included in Revenues 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.
Appalachian Power Co [Member]
Derivatives and Hedging	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. 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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. 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. 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. 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 designated as cash flow hedges are included in Revenues 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. 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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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. 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 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.
Indiana Michigan Power Co [Member]
Derivatives and Hedging	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. 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 designated as cash flow hedges are included in Revenues 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. 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. 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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” The 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. 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 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. 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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.
Ohio Power Co [Member]
Derivatives and Hedging	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. 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. 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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. 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 designated as cash flow hedges are included in Revenues 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 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. 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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” In 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	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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Cash Flow Hedging Strategies 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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. 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 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 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 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. 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. 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 designated as cash flow hedges are included in Revenues 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.
Southwestern Electric Power Co [Member]
Derivatives and Hedging	The accumulated gains or losses related to foreign currency hedges are reclassified from Accumulated Other Comprehensive Income (Loss) on the 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. OBJECTIVES FOR UTILIZATION OF DERIVATIVE INSTRUMENTS The Registrant Subsidiaries are exposed to certain market risks as major power producers and participants in the wholesale electricity, natural gas, coal and emission allowance markets. 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. 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 (“Commodity”) in order to manage the variable price risk related to forecasted purchases and sales. Management monitors the potential impacts of commodity price changes and, where appropriate, enters into derivative transactions to protect profit margins for a portion of future electricity sales and purchases. The 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. In March 2014, these contracts were 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. 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 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. 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. 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. Certain derivatives that economically hedge future commodity risk are recorded in the same expense line item on the condensed statements of income as that of the associated risk. However, unrealized and some realized gains and losses in regulated jurisdictions for both trading and non-trading derivative instruments are recorded as regulatory assets (for losses) or regulatory liabilities (for gains) in accordance with the accounting guidance for “Regulated Operations.” Accounting for Cash Flow Hedging Strategies For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), the 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 designated as cash flow hedges are included in Revenues 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 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. 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 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.

Fair Value Measurements (Polici

Fair Value Measurements (Policies)	6 Months Ended
	Jun. 30, 2015
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 reports regarding compliance with policies, limits and procedures. The Regulated Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer, Executive Vice President of Generation, Senior Vice President of Commercial Operations and Chief Risk Officer. The Competitive Risk Committee consists of AEPSC’s Chief Operating Officer, Chief Financial Officer and Chief Risk Officer in addition to Energy Supply’s President and Vice President. For 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 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.
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 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 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.
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 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.
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 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.

Income Taxes (Policies)

Income Taxes (Policies)	6 Months Ended
	Jun. 30, 2015
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)	6 Months Ended
	Jun. 30, 2015
Variable Interest Entities	The accounting guidance for “Variable Interest Entities” is a consolidation model that considers if a company has a controlling financial interest in a VIE. A controlling financial interest will have both (a) the power to direct the activities of a VIE that most significantly impact the VIE’s economic performance and (b) the obligation to absorb losses of the VIE that could potentially be significant to the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. Entities are required to consolidate a VIE when it is determined that they have a controlling financial interest in a VIE and therefore, are the primary beneficiary of that VIE, as defined by the accounting guidance for “Variable Interest Entities.” In determining whether 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	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	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	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	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	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.

Property, Plant and Equipment28

Property, Plant and Equipment Property, Plant and Equipment (Policies)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligations, Policy	Asset Retirement Obligations (ARO) We record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for our legal obligations for asbestos removal and for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant, wind farms and certain coal mining facilities, as well as for nuclear decommissioning of our Cook Plant. We have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. We do not estimate the retirement for such easements because we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements, which is not expected.
Appalachian Power Co [Member]
Asset Retirement Obligations, Policy	Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.
Indiana Michigan Power Co [Member]
Asset Retirement Obligations, Policy	Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.
Ohio Power Co [Member]
Asset Retirement Obligations, Policy	Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.
Public Service Co Of Oklahoma [Member]
Asset Retirement Obligations, Policy	Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.
Southwestern Electric Power Co [Member]
Asset Retirement Obligations, Policy	Asset Retirement Obligations (ARO) The Registrant Subsidiaries record ARO in accordance with the accounting guidance for “Asset Retirement and Environmental Obligations” for the retirement of certain ash disposal facilities, closure and monitoring of underground carbon storage facilities at Mountaineer Plant and coal mining facilities, as well as asbestos removal. I&M records ARO for the decommissioning of the Cook Plant. The Registrant Subsidiaries have identified, but not recognized, ARO liabilities related to electric transmission and distribution assets as a result of certain easements on property on which assets are owned. Generally, such easements are perpetual and require only the retirement and removal of assets upon the cessation of the property’s use. The retirement obligation is not estimable for such easements since the Registrant Subsidiaries plan to use their facilities indefinitely. The retirement obligation would only be recognized if and when the Registrant Subsidiaries abandon or cease the use of specific easements, which is not expected.

Significant Accounting Matter29

Significant Accounting Matters (Tables)	6 Months Ended
	Jun. 30, 2015
Basic and Diluted EPS Calculations	Three Months Ended June 30, 2015 2014 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 430 $ 390 Weighted Average Number of Basic Shares Outstanding 490.2 $ 0.88 488.3 $ 0.80 Weighted Average Dilutive Effect of Restricted Stock Units 0.3 — 0.2 — Weighted Average Number of Diluted Shares Outstanding 490.5 $ 0.88 488.5 $ 0.80 Six Months Ended June 30, 2015 2014 (in millions, except per share data) $/share $/share Earnings Attributable to AEP Common Shareholders $ 1,059 $ 950 Weighted Average Number of Basic Shares Outstanding 489.9 $ 2.16 488.1 $ 1.95 Weighted Average Dilutive Effect of Restricted Stock Units 0.3 — 0.3 — Weighted Average Number of Diluted Shares Outstanding 490.2 $ 2.16 488.4 $ 1.95

Comprehensive Income (Tables)

Comprehensive Income (Tables)	6 Months Ended
	Jun. 30, 2015
Changes in Accumulated Other Comprehensive Income by Component	Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2015 $ (6 ) $ (18 ) $ 9 $ (88 ) $ (103 ) Change in Fair Value Recognized in AOCI (1 ) — (1 ) — (2 ) Amounts Reclassified from AOCI 2 — — 1 3 Net Current Period Other Comprehensive Income (Loss) 1 — (1 ) 1 1 Balance in AOCI as of June 30, 2015 $ (5 ) $ (18 ) $ 8 $ (87 ) $ (102 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of March 31, 2014 $ 4 $ (22 ) $ 7 $ (98 ) $ (109 ) Change in Fair Value Recognized in AOCI 3 — 1 — 4 Amounts Reclassified from AOCI (1 ) 1 — 1 1 Net Current Period Other Comprehensive Income 2 1 1 1 5 Balance in AOCI as of June 30, 2014 $ 6 $ (21 ) $ 8 $ (97 ) $ (104 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2014 $ 1 $ (19 ) $ 8 $ (93 ) $ (103 ) Change in Fair Value Recognized in AOCI 2 — — — 2 Amounts Reclassified from AOCI (8 ) 1 — 1 (6 ) Net Current Period Other Comprehensive Income (Loss) (6 ) 1 — 1 (4 ) Pension and OPEB Adjustment Related to Mitchell Plant — — — 5 5 Balance in AOCI as of June 30, 2015 $ (5 ) $ (18 ) $ 8 $ (87 ) $ (102 ) Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Securities Available for Sale Pension and OPEB Total (in millions) Balance in AOCI as of December 31, 2013 $ — $ (23 ) $ 7 $ (99 ) $ (115 ) Change in Fair Value Recognized in AOCI (11 ) — 1 — (10 ) Amounts Reclassified from AOCI 17 2 — 2 21 Net Current Period Other Comprehensive Income 6 2 1 2 11 Balance in AOCI as of June 30, 2014 $ 6 $ (21 ) $ 8 $ (97 ) $ (104 )
Reclassifications from Accumulated Other Comprehensive Income	Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Generation & Marketing Revenues $ (4 ) $ — Purchased Electricity for Resale 7 (2 ) Subtotal – Commodity 3 (2 ) Interest Rate and Foreign Currency: Interest Expense — 2 Subtotal – Interest Rate and Foreign Currency — 2 Reclassifications from AOCI, before Income Tax (Expense) Credit 3 — Income Tax (Expense) Credit 1 — Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2 — Pension and OPEB Amortization of Prior Service Cost (Credit) (5 ) (5 ) Amortization of Actuarial (Gains)/Losses 6 7 Reclassifications from AOCI, before Income Tax (Expense) Credit 1 2 Income Tax (Expense) Credit — 1 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1 1 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 3 $ 1 Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in millions) Commodity: Generation & Marketing Revenues $ (17 ) $ — Purchased Electricity for Resale 6 29 Regulatory Assets/(Liabilities), Net (a) — (3 ) Subtotal – Commodity (11 ) 26 Interest Rate and Foreign Currency: Interest Expense 1 4 Subtotal – Interest Rate and Foreign Currency 1 4 Reclassifications from AOCI, before Income Tax (Expense) Credit (10 ) 30 Income Tax (Expense) Credit (3 ) 11 Reclassifications from AOCI, Net of Income Tax (Expense) Credit (7 ) 19 Pension and OPEB Amortization of Prior Service Cost (Credit) (10 ) (10 ) Amortization of Actuarial (Gains)/Losses 11 14 Reclassifications from AOCI, before Income Tax (Expense) Credit 1 4 Income Tax (Expense) Credit — 2 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1 2 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (6 ) $ 21 (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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,025 $ 678 $ 4,703 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 2 (458 ) (456 ) Net Current Period Other Comprehensive Income (Loss) — 2 (458 ) (456 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 87 $ 3,343 $ (566 ) $ 2,864 Change in Fair Value Recognized in AOCI 103 — — 103 Amounts Reclassified from AOCI (190 ) 253 (333 ) (270 ) Net Current Period Other Comprehensive Income (Loss) (87 ) 253 (333 ) (167 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 3,896 $ 1,136 $ 5,032 Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 131 (916 ) (785 ) Net Current Period Other Comprehensive Income (Loss) — 131 (916 ) (785 ) Balance in AOCI as of June 30, 2015 $ — $ 4,027 $ 220 $ 4,247 APCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,686 — — 1,686 Amounts Reclassified from AOCI (1,780 ) 506 (666 ) (1,940 ) Net Current Period Other Comprehensive Income (Loss) (94 ) 506 (666 ) (254 ) Balance in AOCI as of June 30, 2014 $ — $ 3,596 $ (899 ) $ 2,697
Reclassifications from Accumulated Other Comprehensive Income	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Reclassified from AOCI Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (64 ) Regulatory Assets/(Liabilities), Net (a) — (228 ) Subtotal – Commodity — (292 ) Interest Rate and Foreign Currency: Interest Expense 3 390 Subtotal – Interest Rate and Foreign Currency 3 390 Reclassifications from AOCI, before Income Tax (Expense) Credit 3 98 Income Tax (Expense) Credit 1 35 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 2 63 Pension and OPEB Amortization of Prior Service Cost (Credit) (1,283 ) (1,283 ) Amortization of Actuarial (Gains)/Losses 578 770 Reclassifications from AOCI, before Income Tax (Expense) Credit (705 ) (513 ) Income Tax (Expense) Credit (247 ) (180 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (458 ) (333 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (456 ) $ (270 ) APCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (526 ) Other Operation Expense — (10 ) Maintenance Expense — (20 ) Property, Plant and Equipment — (17 ) Regulatory Assets/(Liabilities), Net (a) — (2,165 ) Subtotal – Commodity — (2,738 ) Interest Rate and Foreign Currency: Interest Expense 202 780 Subtotal – Interest Rate and Foreign Currency 202 780 Reclassifications from AOCI, before Income Tax (Expense) Credit 202 (1,958 ) Income Tax (Expense) Credit 71 (684 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 131 (1,274 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (2,565 ) (2,565 ) Amortization of Actuarial (Gains)/Losses 1,156 1,540 Reclassifications from AOCI, before Income Tax (Expense) Credit (1,409 ) (1,025 ) Income Tax (Expense) Credit (493 ) (359 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (916 ) (666 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (785 ) $ (1,940 )
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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (14,139 ) $ 58 $ (14,081 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 268 10 278 Net Current Period Other Comprehensive Income — 268 10 278 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ 61 $ (15,566 ) $ 464 $ (15,041 ) Change in Fair Value Recognized in AOCI 68 — — 68 Amounts Reclassified from AOCI (129 ) 411 43 325 Net Current Period Other Comprehensive Income (Loss) (61 ) 411 43 393 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (14,406 ) $ 46 $ (14,360 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 535 22 557 Net Current Period Other Comprehensive Income — 535 22 557 Balance in AOCI as of June 30, 2015 $ — $ (13,871 ) $ 68 $ (13,803 ) I&M Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 1,130 — — 1,130 Amounts Reclassified from AOCI (1,176 ) 821 86 (269 ) Net Current Period Other Comprehensive Income (Loss) (46 ) 821 86 861 Balance in AOCI as of June 30, 2014 $ — $ (15,155 ) $ 507 $ (14,648 )
Reclassifications from Accumulated Other Comprehensive Income	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (95 ) Regulatory Assets/(Liabilities), Net (a) — (103 ) Subtotal – Commodity — (198 ) Interest Rate and Foreign Currency: Interest Expense 411 631 Subtotal – Interest Rate and Foreign Currency 411 631 Reclassifications from AOCI, before Income Tax (Expense) Credit 411 433 Income Tax (Expense) Credit 143 151 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 268 282 Pension and OPEB Amortization of Prior Service Cost (Credit) (199 ) (198 ) Amortization of Actuarial (Gains)/Losses 215 262 Reclassifications from AOCI, before Income Tax (Expense) Credit 16 64 Income Tax (Expense) Credit 6 21 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 10 43 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 278 $ 325 I&M Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Purchased Electricity for Resale $ — $ (812 ) Other Operation Expense — (7 ) Maintenance Expense — (7 ) Property, Plant and Equipment — (10 ) Regulatory Assets/(Liabilities), Net (a) — (973 ) Subtotal – Commodity — (1,809 ) Interest Rate and Foreign Currency: Interest Expense 822 1,262 Subtotal – Interest Rate and Foreign Currency 822 1,262 Reclassifications from AOCI, before Income Tax (Expense) Credit 822 (547 ) Income Tax (Expense) Credit 287 (192 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit 535 (355 ) Pension and OPEB Amortization of Prior Service Cost (Credit) (398 ) (397 ) Amortization of Actuarial (Gains)/Losses 432 527 Reclassifications from AOCI, before Income Tax (Expense) Credit 34 130 Income Tax (Expense) Credit 12 44 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 22 86 Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 557 $ (269 )
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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 5,259 $ 5,259 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 6,631 $ 6,631 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (343 ) (343 ) Net Current Period Other Comprehensive Loss — (343 ) (343 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 5,602 $ 5,602 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (686 ) (686 ) Net Current Period Other Comprehensive Loss — (686 ) (686 ) Balance in AOCI as of June 30, 2015 $ — $ 4,916 $ 4,916 OPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency 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 ) (686 ) (791 ) Net Current Period Other Comprehensive Loss (105 ) (686 ) (791 ) Balance in AOCI as of June 30, 2014 $ — $ 6,288 $ 6,288
Reclassifications from Accumulated Other Comprehensive Income	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — Interest Rate and Foreign Currency: Depreciation and Amortization Expense (3 ) (3 ) Interest Expense (524 ) (524 ) Subtotal – Interest Rate and Foreign Currency (527 ) (527 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (527 ) (527 ) Income Tax (Expense) Credit (184 ) (184 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (343 ) $ (343 ) OPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (11 ) Maintenance Expense — (11 ) Property, Plant and Equipment — (18 ) Regulatory Assets/(Liabilities), Net (a) — (122 ) Subtotal – Commodity — (162 ) Interest Rate and Foreign Currency: Depreciation and Amortization Expense (6 ) (6 ) Interest Expense (1,048 ) (1,048 ) Subtotal – Interest Rate and Foreign Currency (1,054 ) (1,054 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (1,054 ) (1,216 ) Income Tax (Expense) Credit (368 ) (425 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (686 ) $ (791 )
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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ 4,753 $ 4,753 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ 5,512 $ 5,512 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (190 ) (190 ) Net Current Period Other Comprehensive Loss — (190 ) (190 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ 4,943 $ 4,943 Change in Fair Value Recognized in AOCI — — — Amounts Reclassified from AOCI — (380 ) (380 ) Net Current Period Other Comprehensive Loss — (380 ) (380 ) Balance in AOCI as of June 30, 2015 $ — $ 4,563 $ 4,563 PSO Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and 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 ) (379 ) (436 ) Net Current Period Other Comprehensive Loss (57 ) (379 ) (436 ) Balance in AOCI as of June 30, 2014 $ — $ 5,322 $ 5,322
Reclassifications from Accumulated Other Comprehensive Income	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 (292 ) (292 ) Income Tax (Expense) Credit (102 ) (102 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (190 ) $ (190 ) PSO Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (8 ) Maintenance Expense — (9 ) Property, Plant and Equipment — (13 ) Regulatory Assets/(Liabilities), Net (a) — (58 ) Subtotal – Commodity — (88 ) Interest Rate and Foreign Currency: Interest Expense (584 ) (584 ) Subtotal – Interest Rate and Foreign Currency (584 ) (584 ) Reclassifications from AOCI, before Income Tax (Expense) Credit (584 ) (672 ) Income Tax (Expense) Credit (204 ) (236 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ (380 ) $ (436 )
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 June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2015 $ — $ (10,469 ) $ 3,330 $ (7,139 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (239 ) 328 Net Current Period Other Comprehensive Income (Loss) — 567 (239 ) 328 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Three Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of March 31, 2014 $ — $ (12,736 ) $ 4,560 $ (8,176 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 567 (235 ) 332 Net Current Period Other Comprehensive Income (Loss) — 567 (235 ) 332 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2015 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension and OPEB Total (in thousands) Balance in AOCI as of December 31, 2014 $ — $ (11,036 ) $ 3,570 $ (7,466 ) Change in Fair Value Recognized in AOCI — — — — Amounts Reclassified from AOCI — 1,134 (479 ) 655 Net Current Period Other Comprehensive Income (Loss) — 1,134 (479 ) 655 Balance in AOCI as of June 30, 2015 $ — $ (9,902 ) $ 3,091 $ (6,811 ) SWEPCo Changes in Accumulated Other Comprehensive Income (Loss) by Component For the Six Months Ended June 30, 2014 Cash Flow Hedges Commodity Interest Rate and Foreign Currency Pension 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 ) 1,135 (469 ) 600 Net Current Period Other Comprehensive Income (Loss) (66 ) 1,135 (469 ) 600 Balance in AOCI as of June 30, 2014 $ — $ (12,169 ) $ 4,325 $ (7,844 )
Reclassifications from Accumulated Other Comprehensive Income	(a) Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets. SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Three Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Three Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ — Maintenance Expense — — Property, Plant and Equipment — — Regulatory Assets/(Liabilities), Net (a) — — Subtotal – Commodity — — 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 872 872 Income Tax (Expense) Credit 305 305 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 567 567 Pension and OPEB Amortization of Prior Service Cost (Credit) (467 ) (477 ) Amortization of Actuarial (Gains)/Losses 99 115 Reclassifications from AOCI, before Income Tax (Expense) Credit (368 ) (362 ) Income Tax (Expense) Credit (129 ) (127 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (239 ) (235 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 328 $ 332 SWEPCo Reclassifications from Accumulated Other Comprehensive Income (Loss) For the Six Months Ended June 30, 2015 and 2014 Amount of (Gain) Loss Six Months Ended June 30, 2015 2014 Gains and Losses on Cash Flow Hedges (in thousands) Commodity: Other Operation Expense $ — $ (13 ) Maintenance Expense — (10 ) Property, Plant and Equipment — (11 ) Regulatory Assets/(Liabilities), Net (a) — (67 ) Subtotal – Commodity — (101 ) Interest Rate and Foreign Currency: Interest Expense 1,744 1,744 Subtotal – Interest Rate and Foreign Currency 1,744 1,744 Reclassifications from AOCI, before Income Tax (Expense) Credit 1,744 1,643 Income Tax (Expense) Credit 610 574 Reclassifications from AOCI, Net of Income Tax (Expense) Credit 1,134 1,069 Pension and OPEB Amortization of Prior Service Cost (Credit) (934 ) (955 ) Amortization of Actuarial (Gains)/Losses 197 233 Reclassifications from AOCI, before Income Tax (Expense) Credit (737 ) (722 ) Income Tax (Expense) Credit (258 ) (253 ) Reclassifications from AOCI, Net of Income Tax (Expense) Credit (479 ) (469 ) Total Reclassifications from AOCI, Net of Income Tax (Expense) Credit $ 655 $ 600

Rate Matters (Tables)

Rate Matters (Tables)	6 Months Ended
	Jun. 30, 2015
Regulatory Assets Not Yet Being Recovered	Regulatory Assets Pending Final Regulatory Approval June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in millions) Regulatory Assets Currently Earning a Return Storm Related Costs $ 20 $ 20 Material and Supplies Related to Retired Plants 19 — West Virginia Vegetation Management Program — 20 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 51 — Virginia Demand Response Program Costs 11 9 Ormet Special Rate Recovery Mechanism 10 10 Storm Related Costs 3 100 Carbon Capture and Storage Product Validation Facility — 13 IGCC Pre-Construction Costs — 11 Other Regulatory Assets Pending Final Regulatory Approval 23 43 Total Regulatory Assets Pending Final Regulatory Approval $ 137 $ 226
Appalachian Power Co [Member]
Regulatory Assets Not Yet Being Recovered	APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115
Indiana Michigan Power Co [Member]
Regulatory Assets Not Yet Being Recovered	APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115
Ohio Power Co [Member]
Regulatory Assets Not Yet Being Recovered	APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115
Public Service Co Of Oklahoma [Member]
Regulatory Assets Not Yet Being Recovered	Regulatory Assets Pending Final Regulatory Approval APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115
Southwestern Electric Power Co [Member]
Regulatory Assets Not Yet Being Recovered	APCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 7,588 $ — Vegetation Management Program – West Virginia — 19,089 Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 24,399 — Demand Response Program Costs – Virginia 10,781 8,791 Amos Plant Transfer Costs – West Virginia 1,950 1,377 Storm Related Costs – West Virginia — 65,206 Carbon Capture and Storage Product Validation Facility – West Virginia, FERC — 13,264 IGCC Pre-Construction Costs – West Virginia, FERC — 10,838 Expanded Net Energy Charge – Coal Inventory — 3,421 Expanded Net Energy Charge – Construction Surcharge — 2,307 Carbon Capture and Storage Commercial Scale Facility – West Virginia, FERC — 1,287 Other Regulatory Assets Pending Final Regulatory Approval 168 168 Total Regulatory Assets Pending Final Regulatory Approval $ 44,886 $ 125,748 I&M June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Earning a Return Materials and Supplies Related to Retired Plants $ 11,722 $ — Regulatory Assets Currently Not Earning a Return Asset Retirement Obligation Costs Related to Retired Plants 27,079 — Cook Plant Turbine 8,169 6,596 Stranded Costs on Abandoned Plants 3,897 3,897 Deferred Cook Plant Life Cycle Management Project Costs – Michigan 2,721 1,222 Storm Related Costs – Indiana 857 1,074 Other Regulatory Assets Pending Final Regulatory Approval 547 860 Total Regulatory Assets Pending Final Regulatory Approval $ 54,992 $ 13,649 OPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Ormet Special Rate Recovery Mechanism $ 10,483 $ 10,483 Other Regulatory Assets Pending Final Regulatory Approval 44 — Total Regulatory Assets Pending Final Regulatory Approval $ 10,527 $ 10,483 PSO June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Storm Related Costs $ — $ 16,614 Other Regulatory Assets Pending Final Regulatory Approval — 1,079 Total Regulatory Assets Pending Final Regulatory Approval $ — $ 17,693 SWEPCo June 30, December 31, 2015 2014 Noncurrent Regulatory Assets (in thousands) Regulatory Assets Currently Not Earning a Return Rate Case Expenses $ — $ 8,126 Shipe Road Transmission Project 3,022 2,287 Asset Retirement Obligation 1,320 1,144 Other Regulatory Assets Pending Final Regulatory Approval 558 558 Total Regulatory Assets Pending Final Regulatory Approval $ 4,900 $ 12,115

Commitments, Guarantees and C32

Commitments, Guarantees and Contingencies (Tables)	6 Months Ended
	Jun. 30, 2015
Appalachian Power Co [Member]
Maximum Future Payments of Letters of Credit	Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825
Indiana Michigan Power Co [Member]
Maximum Future Payments of Letters of Credit	Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825
Ohio Power Co [Member]
Maximum Future Payments of Letters of Credit	Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825
Public Service Co Of Oklahoma [Member]
Maximum Future Payments of Letters of Credit	Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825
Southwestern Electric Power Co [Member]
Maximum Future Payments of Letters of Credit	Company Amount Maturity (in thousands) I&M $ 35 March 2016 OPCo 4,200 June 2016
Pollution Control Bonds Supported by Bilateral Letters of Credit	Company Pollution Control Bonds Bilateral Letters of Credit Maturity of Bilateral Letters of Credit (in thousands) APCo $ 229,650 $ 232,293 March 2016 to March 2017 I&M 77,000 77,886 March 2017
Maximum Potential Loss on Master Lease Agreements	Company Maximum Potential Loss (in thousands) APCo $ 4,864 I&M 3,323 OPCo 5,618 PSO 2,428 SWEPCo 2,825

Benefit Plans (Tables)

Benefit Plans (Tables)	6 Months Ended
	Jun. 30, 2015
Components of Net Periodic Benefit Cost	Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in millions) Service Cost $ 24 $ 18 $ 3 $ 3 Interest Cost 52 56 14 17 Expected Return on Plan Assets (68 ) (65 ) (27 ) (28 ) Amortization of Prior Service Credit — — (17 ) (17 ) Amortization of Net Actuarial Loss 26 31 4 6 Net Periodic Benefit Cost (Credit) $ 34 $ 40 $ (23 ) $ (19 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in millions) Service Cost $ 47 $ 36 $ 6 $ 7 Interest Cost 103 111 28 34 Expected Return on Plan Assets (137 ) (131 ) (55 ) (56 ) Amortization of Prior Service Cost (Credit) 1 1 (34 ) (34 ) Amortization of Net Actuarial Loss 53 62 9 11 Net Periodic Benefit Cost (Credit) $ 67 $ 79 $ (46 ) $ (38 )
Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost	APCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,175 $ 1,759 $ 285 $ 362 Interest Cost 6,679 7,406 2,585 3,197 Expected Return on Plan Assets (8,746 ) (8,481 ) (4,529 ) (4,633 ) Amortization of Prior Service Cost (Credit) 45 49 (2,512 ) (2,512 ) Amortization of Net Actuarial Loss 3,474 4,148 899 1,145 Net Periodic Benefit Cost (Credit) $ 3,627 $ 4,881 $ (3,272 ) $ (2,441 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,350 $ 3,518 $ 571 $ 724 Interest Cost 13,358 14,812 5,169 6,394 Expected Return on Plan Assets (17,491 ) (16,963 ) (9,058 ) (9,266 ) Amortization of Prior Service Cost (Credit) 90 99 (5,025 ) (5,025 ) Amortization of Net Actuarial Loss 6,947 8,296 1,799 2,291 Net Periodic Benefit Cost (Credit) $ 7,254 $ 9,762 $ (6,544 ) $ (4,882 )
Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost	I&M Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,217 $ 2,517 $ 407 $ 487 Interest Cost 6,115 6,574 1,592 1,910 Expected Return on Plan Assets (8,116 ) (7,748 ) (3,304 ) (3,363 ) Amortization of Prior Service Cost (Credit) 46 48 (2,356 ) (2,356 ) Amortization of Net Actuarial Loss 3,144 3,646 507 592 Net Periodic Benefit Cost (Credit) $ 4,406 $ 5,037 $ (3,154 ) $ (2,730 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 6,434 $ 5,034 $ 813 $ 974 Interest Cost 12,230 13,147 3,184 3,819 Expected Return on Plan Assets (16,232 ) (15,496 ) (6,608 ) (6,727 ) Amortization of Prior Service Cost (Credit) 91 97 (4,711 ) (4,711 ) Amortization of Net Actuarial Loss 6,289 7,292 1,013 1,184 Net Periodic Benefit Cost (Credit) $ 8,812 $ 10,074 $ (6,309 ) $ (5,461 )
Ohio Power Co [Member]
Components of Net Periodic Benefit Cost	OPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,672 $ 1,285 $ 215 $ 257 Interest Cost 5,070 5,526 1,615 1,900 Expected Return on Plan Assets (6,878 ) (6,606 ) (3,378 ) (3,380 ) Amortization of Prior Service Cost (Credit) 35 39 (1,730 ) (1,730 ) Amortization of Net Actuarial Loss 2,644 3,105 518 595 Net Periodic Benefit Cost (Credit) $ 2,543 $ 3,349 $ (2,760 ) $ (2,358 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,344 $ 2,570 $ 431 $ 513 Interest Cost 10,140 11,052 3,230 3,801 Expected Return on Plan Assets (13,756 ) (13,213 ) (6,754 ) (6,760 ) Amortization of Prior Service Cost (Credit) 70 78 (3,461 ) (3,461 ) Amortization of Net Actuarial Loss 5,288 6,211 1,035 1,190 Net Periodic Benefit Cost (Credit) $ 5,086 $ 6,698 $ (5,519 ) $ (4,717 )
Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost	PSO Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 1,599 $ 1,302 $ 169 $ 210 Interest Cost 2,732 3,014 759 894 Expected Return on Plan Assets (3,786 ) (3,651 ) (1,577 ) (1,575 ) Amortization of Prior Service Cost (Credit) 63 74 (1,072 ) (1,073 ) Amortization of Net Actuarial Loss 1,417 1,688 241 277 Net Periodic Benefit Cost (Credit) $ 2,025 $ 2,427 $ (1,480 ) $ (1,267 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 3,198 $ 2,604 $ 339 $ 420 Interest Cost 5,463 6,028 1,518 1,787 Expected Return on Plan Assets (7,572 ) (7,302 ) (3,154 ) (3,150 ) Amortization of Prior Service Cost (Credit) 126 148 (2,145 ) (2,145 ) Amortization of Net Actuarial Loss 2,834 3,376 483 554 Net Periodic Benefit Cost (Credit) $ 4,049 $ 4,854 $ (2,959 ) $ (2,534 )
Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost	SWEPCo Pension Plans Other Postretirement Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 2,082 $ 1,654 $ 210 $ 253 Interest Cost 2,932 3,162 838 998 Expected Return on Plan Assets (4,008 ) (3,857 ) (1,736 ) (1,754 ) Amortization of Prior Service Cost (Credit) 77 88 (1,289 ) (1,289 ) Amortization of Net Actuarial Loss 1,507 1,762 266 308 Net Periodic Benefit Cost (Credit) $ 2,590 $ 2,809 $ (1,711 ) $ (1,484 ) Pension Plans Other Postretirement Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Service Cost $ 4,163 $ 3,309 $ 421 $ 506 Interest Cost 5,864 6,325 1,675 1,996 Expected Return on Plan Assets (8,016 ) (7,714 ) (3,471 ) (3,508 ) Amortization of Prior Service Cost (Credit) 154 175 (2,578 ) (2,578 ) Amortization of Net Actuarial Loss 3,014 3,523 532 617 Net Periodic Benefit Cost (Credit) $ 5,179 $ 5,618 $ (3,421 ) $ (2,967 )

Business Segments (Tables)

Business Segments (Tables)	6 Months Ended
	Jun. 30, 2015
Segment Reporting [Abstract]
Reportable Segment Information	Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,159 $ 1,008 $ 25 $ 628 $ 115 $ 7 $ — (c) $ 3,942 Other Operating Segments 24 53 74 173 13 17 (354 ) — Total Revenues $ 2,183 $ 1,061 $ 99 $ 801 $ 128 $ 24 $ (354 ) $ 3,942 Net Income (Loss) $ 208 $ 78 $ 65 $ 82 $ 1 $ (3 ) $ — $ 431 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended Revenues from: External Customers $ 2,236 (b) $ 1,064 $ 21 $ 573 (b) $ 140 $ 10 $ — (c) $ 4,044 Other Operating Segments 16 (b) 70 36 340 (b) 20 12 (494 ) — Total Revenues $ 2,252 $ 1,134 $ 57 $ 913 $ 160 $ 22 $ (494 ) $ 4,044 Net Income (Loss) $ 155 $ 90 $ 47 $ 98 $ 3 $ (2 ) $ — $ 391 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended Revenues from: External Customers $ 4,646 $ 2,214 $ 47 $ 1,487 $ 243 $ 13 $ — (c) $ 8,650 Other Operating Segments 42 117 110 484 24 37 (814 ) — Total Revenues $ 4,688 $ 2,331 $ 157 $ 1,971 $ 267 $ 50 $ (814 ) $ 8,650 Net Income (Loss) $ 508 $ 175 $ 102 $ 269 $ 12 $ (4 ) $ — $ 1,062 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) Six Months Ended Revenues from: External Customers $ 4,785 (b) $ 2,225 $ 33 $ 1,394 (b) $ 286 $ 20 $ (51 ) (c) $ 8,692 Other Operating Segments 53 (b) 124 52 770 (b) 39 28 (1,066 ) — Total Revenues $ 4,838 $ 2,349 $ 85 $ 2,164 $ 325 $ 48 $ (1,117 ) $ 8,692 Net Income (Loss) $ 434 $ 187 $ 71 $ 261 $ 6 $ (7 ) $ — $ 952 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation & Marketing AEP River Operations Corporate and Other (a) Reconciling Adjustments Consolidated (in millions) June 30, 2015 Total Property, Plant and Equipment $ 39,561 $ 13,506 $ 3,275 $ 7,456 $ 726 $ 357 $ (279 ) (d) $ 64,602 Accumulated Depreciation and Amortization 12,343 3,565 34 3,344 227 181 (105 ) (d) 19,589 Total Property Plant and Equipment - Net $ 27,218 $ 9,941 $ 3,241 $ 4,112 $ 499 $ 176 $ (174 ) (d) $ 45,013 Total Assets $ 35,316 $ 14,351 $ 4,036 $ 5,668 $ 756 $ 21,599 $ (20,788 ) (d) (e) $ 60,938 Long-term Debt Due Within One Year: Affiliated $ — $ — $ — $ — $ — $ — $ — $ — Non-Affiliated 894 678 — 240 3 2 — 1,817 Long-term Debt: Affiliated 20 — — 32 — — (52 ) — Non-Affiliated 10,146 4,729 1,315 648 79 844 — 17,761 Total Long-term Debt $ 11,060 $ 5,407 $ 1,315 $ 920 $ 82 $ 846 $ (52 ) $ 19,578 Vertically Integrated Utilities Transmission and Distribution Utilities AEP Transmission Holdco Generation AEP River Operations Corporate and Other (a) Reconciling Consolidated (in millions) December 31, 2014 Total Property, Plant and Equipment $ 39,402 $ 13,024 $ 2,714 $ 8,394 $ 700 $ 343 $ (272 ) (d) $ 64,305 Accumulated Depreciation and Amortization 12,773 3,481 25 3,603 217 188 (99 ) (d) 20,188 Total Property Plant and Equipment - Net $ 26,629 $ 9,543 $ 2,689 $ 4,791 $ 483 $ 155 $ (173 ) (d) $ 44,117 Total Assets $ 33,750 $ 14,495 $ 3,575 $ 6,329 $ 749 $ 21,081 $ (20,346 ) (d) (e) $ 59,633 Long-term Debt Due Within One Year: Affiliated $ 111 $ — $ — $ 86 $ — $ — $ (197 ) $ — Non-Affiliated 1,352 405 — 740 3 3 — 2,503 Long-term Debt: Affiliated 20 — — 32 — — (52 ) — Non-Affiliated 8,634 5,256 1,153 217 80 841 — 16,181 Total Long-term Debt $ 10,117 $ 5,661 $ 1,153 $ 1,075 $ 83 $ 844 $ (249 ) $ 18,684 (a) Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. (b) Includes the impact of corporate separation of OPCo's generation assets and liabilities that took effect December 31, 2013, as well as the impact of the termination of the Interconnection Agreement effective January 1, 2014. (c) Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio. (d) Includes eliminations due to an intercompany capital lease. (e) Reconciling Adjustments for Total Assets primarily include the elimination of intercompany advances to affiliates and intercompany accounts receivable along with the elimination of AEP's investments in subsidiary companies.

Derivatives and Hedging (Tables

Derivatives and Hedging (Tables)	6 Months Ended
	Jun. 30, 2015
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments Volume June 30, December 31, Unit of Measure Primary Risk Exposure (in millions) Commodity: Power 440 334 MWhs Coal 2 3 Tons Natural Gas 73 106 MMBtus Heating Oil and Gasoline 8 6 Gallons Interest Rate $ 129 $ 152 USD Interest Rate and Foreign Currency $ 564 $ 815 USD
Fair Value of Derivative Instruments	Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in millions) Current Risk Management Assets $ 390 $ 22 $ 2 $ 414 $ (242 ) $ 172 Long-term Risk Management Assets 451 4 — 455 (92 ) 363 Total Assets 841 26 2 869 (334 ) 535 Current Risk Management Liabilities 311 18 1 330 (252 ) 78 Long-term Risk Management Liabilities 258 17 5 280 (106 ) 174 Total Liabilities 569 35 6 610 (358 ) 252 Total MTM Derivative Contract Net Assets (Liabilities) $ 272 $ (9 ) $ (4 ) $ 259 $ 24 $ 283 Fair Value of Derivative Instruments December 31, 2014 Risk Management Hedging Contracts Gross Amounts Gross Net Amounts of Balance Sheet Location Commodity (a) Commodity (a) Interest Rate (in millions) Current Risk Management Assets $ 392 $ 30 $ 3 $ 425 $ (247 ) $ 178 Long-term Risk Management Assets 367 3 — 370 (76 ) 294 Total Assets 759 33 3 795 (323 ) 472 Current Risk Management Liabilities 329 23 1 353 (261 ) 92 Long-term Risk Management Liabilities 208 8 9 225 (94 ) 131 Total Liabilities 537 31 10 578 (355 ) 223 Total MTM Derivative Contract Net Assets (Liabilities) $ 222 $ 2 $ (7 ) $ 217 $ 32 $ 249 (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 and Six Months Ended June 30, 2015 and 2014 Three Months Ended Six Months Ended June 30, June 30, Location of Gain (Loss) 2015 2014 2015 2014 (in millions) Vertically Integrated Utilities Revenues $ 1 $ 4 $ 7 $ 22 Generation & Marketing Revenues 10 16 59 48 Other Operation Expense — — (2 ) — Maintenance Expense — — (1 ) — Purchased Electricity for Resale — — 4 — Regulatory Assets (a) 4 — — — Regulatory Liabilities (a) 49 29 53 118 Total Gain on Risk Management Contracts $ 64 $ 49 $ 120 $ 188 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Gain (Loss) on Hedging Instruments	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in millions) Gain on Fair Value Hedging Instruments $ 1 $ 2 $ 6 $ 4 Loss on Fair Value Portion of Long-term Debt (1 ) (2 ) (6 ) (4 )
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Condensed Balance Sheet June 30, 2015 Commodity Interest Rate Currency Total (in millions) Hedging Assets (a) $ 10 $ — $ 10 Hedging Liabilities (a) 19 1 20 AOCI Loss Net of Tax (5 ) (18 ) (23 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4 (1 ) 3 Impact of Cash Flow Hedges on the Condensed Balance Sheet December 31, 2014 Commodity Interest Rate Total (in millions) Hedging Assets (a) $ 16 $ — $ 16 Hedging Liabilities (a) 14 1 15 AOCI Gain (Loss) Net of Tax 1 (19 ) (18 ) Portion Expected to be Reclassified to Net Income During the Next Twelve Months 4 (2 ) 2 (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	June 30, December 31, 2015 2014 (in millions) Fair Value of Contracts with Credit Downgrade Triggers $ — $ — Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement — — Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs 31 36 Amount of Collateral Attributable to Other Contracts (a) 304 281 (a) Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contracts.
Liabilities Subject to Cross Default Provisions	June 30, December 31, (in millions) Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements $ 287 $ 235 Amount of Cash Collateral Posted 5 9 Additional Settlement Liability if Cross Default Provision is Triggered 225 178
Appalachian Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ —
Cash Collateral Netting	June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62
Fair Value of Derivative Instruments	APCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 52,015 $ — $ — $ 52,015 $ (13,138 ) $ 38,877 Long-term Risk Management Assets 3,286 — — 3,286 (284 ) 3,002 Total Assets 55,301 — — 55,301 (13,422 ) 41,879 Current Risk Management Liabilities 23,210 — — 23,210 (14,051 ) 9,159 Long-term Risk Management Liabilities 1,734 — — 1,734 (286 ) 1,448 Total Liabilities 24,944 — — 24,944 (14,337 ) 10,607 Total MTM Derivative Contract Net Assets (Liabilities) $ 30,357 $ — $ — $ 30,357 $ 915 $ 31,272 APCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 32,903 $ — $ — $ 32,903 $ (9,111 ) $ 23,792 Long-term Risk Management Assets 5,159 — — 5,159 (268 ) 4,891 Total Assets 38,062 — — 38,062 (9,379 ) 28,683 Current Risk Management Liabilities 20,161 — — 20,161 (9,144 ) 11,017 Long-term Risk Management Liabilities 2,322 — — 2,322 (265 ) 2,057 Total Liabilities 22,483 — — 22,483 (9,409 ) 13,074 Total MTM Derivative Contract Net Assets (Liabilities) $ 15,579 $ — $ — $ 15,579 $ 30 $ 15,609 (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 June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Affiliated Derivative Transactions	June 30, 2015 Company Risk Management Assets Regulatory Liabilities and Deferred Investment Tax Credits (in thousands) APCo $ 2,690 $ 2,690 I&M 3,137 3,137
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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	June 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 3,211 $ 987 I&M — — 2,178 215 OPCo — — — — PSO — — 244 6,783 SWEPCo — — 293 210 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166
Liabilities Subject to Cross Default Provisions	June 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 6,795 $ — $ 6,715 I&M 4,609 — 4,554 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 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 $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — —
Indiana Michigan Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ —
Cash Collateral Netting	June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62
Fair Value of Derivative Instruments	I&M Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 26,147 $ — $ — $ 26,147 $ (9,633 ) $ 16,514 Long-term Risk Management Assets 2,219 — — 2,219 (193 ) 2,026 Total Assets 28,366 — — 28,366 (9,826 ) 18,540 Current Risk Management Liabilities 14,553 — — 14,553 (10,060 ) 4,493 Long-term Risk Management Liabilities 1,176 — — 1,176 (194 ) 982 Total Liabilities 15,729 — — 15,729 (10,254 ) 5,475 Total MTM Derivative Contract Net Assets (Liabilities) $ 12,637 $ — $ — $ 12,637 $ 428 $ 13,065 I&M Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 28,545 $ — $ — $ 28,545 $ (6,217 ) $ 22,328 Long-term Risk Management Assets 3,499 — — 3,499 (182 ) 3,317 Total Assets 32,044 — — 32,044 (6,399 ) 25,645 Current Risk Management Liabilities 11,326 — — 11,326 (6,103 ) 5,223 Long-term Risk Management Liabilities 1,575 — — 1,575 (180 ) 1,395 Total Liabilities 12,901 — — 12,901 (6,283 ) 6,618 Total MTM Derivative Contract Net Assets (Liabilities) $ 19,143 $ — $ — $ 19,143 $ (116 ) $ 19,027 (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 June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (a) Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
Affiliated Derivative Transactions	June 30, 2015 Company Risk Management Assets Regulatory Liabilities and Deferred Investment Tax Credits (in thousands) APCo $ 2,690 $ 2,690 I&M 3,137 3,137
Impact of Cash Flow Hedges on the Condensed Balance Sheet	Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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	June 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 3,211 $ 987 I&M — — 2,178 215 OPCo — — — — PSO — — 244 6,783 SWEPCo — — 293 210 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166
Liabilities Subject to Cross Default Provisions	June 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 6,795 $ — $ 6,715 I&M 4,609 — 4,554 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 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 $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — —
Ohio Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ —
Cash Collateral Netting	June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62
Fair Value of Derivative Instruments	OPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 70 $ — $ — $ 70 $ (70 ) $ — Long-term Risk Management Assets 44,056 — — 44,056 — 44,056 Total Assets 44,126 — — 44,126 (70 ) 44,056 Current Risk Management Liabilities 2,201 — — 2,201 (191 ) 2,010 Long-term Risk Management Liabilities 4,573 — — 4,573 — 4,573 Total Liabilities 6,774 — — 6,774 (191 ) 6,583 Total MTM Derivative Contract Net Assets (Liabilities) $ 37,352 $ — $ — $ 37,352 $ 121 $ 37,473 OPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 7,242 $ — $ — $ 7,242 $ — $ 7,242 Long-term Risk Management Assets 45,102 — — 45,102 — 45,102 Total Assets 52,344 — — 52,344 — 52,344 Current Risk Management Liabilities 2,045 — — 2,045 (102 ) 1,943 Long-term Risk Management Liabilities 3,013 — — 3,013 — 3,013 Total Liabilities 5,058 — — 5,058 (102 ) 4,956 Total MTM Derivative Contract Net Assets (Liabilities) $ 47,286 $ — $ — $ 47,286 $ 102 $ 47,388 (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 June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (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 June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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	June 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 3,211 $ 987 I&M — — 2,178 215 OPCo — — — — PSO — — 244 6,783 SWEPCo — — 293 210 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166
Liabilities Subject to Cross Default Provisions	June 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 6,795 $ — $ 6,715 I&M 4,609 — 4,554 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 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 $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — —
Public Service Co Of Oklahoma [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ —
Cash Collateral Netting	June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62
Fair Value of Derivative Instruments	PSO Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 1,821 $ — $ — $ 1,821 $ (90 ) $ 1,731 Long-term Risk Management Assets 29 — — 29 — 29 Total Assets 1,850 — — 1,850 (90 ) 1,760 Current Risk Management Liabilities 334 — — 334 (205 ) 129 Long-term Risk Management Liabilities — — — — — — Total Liabilities 334 — — 334 (205 ) 129 Total MTM Derivative Contract Net Assets (Liabilities) $ 1,516 $ — $ — $ 1,516 $ 115 $ 1,631 PSO Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 360 $ — $ — $ 360 $ (360 ) $ — Long-term Risk Management Assets — — — — — — Total Assets 360 — — 360 (360 ) — Current Risk Management Liabilities 1,332 — — 1,332 (414 ) 918 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,332 — — 1,332 (414 ) 918 Total MTM Derivative Contract Net Assets (Liabilities) $ (972 ) $ — $ — $ (972 ) $ 54 $ (918 ) (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 June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (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 June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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	June 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 3,211 $ 987 I&M — — 2,178 215 OPCo — — — — PSO — — 244 6,783 SWEPCo — — 293 210 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166
Liabilities Subject to Cross Default Provisions	June 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 6,795 $ — $ 6,715 I&M 4,609 — 4,554 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 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 $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — —
Southwestern Electric Power Co [Member]
Notional Volume of Derivative Instruments	Notional Volume of Derivative Instruments June 30, 2015 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 82,828 38,036 5,428 26,530 31,839 Coal Tons 232 250 — — 750 Natural Gas MMBtus 339 227 — 12 14 Heating Oil and Gasoline Gallons 1,468 695 1,546 852 975 Interest Rate USD $ 3,590 $ 2,435 $ — $ — $ — Notional Volume of Derivative Instruments December 31, 2014 Primary Risk Exposure Unit of Measure APCo I&M OPCo PSO SWEPCo (in thousands) Commodity: Power MWhs 32,479 23,774 20,334 16,765 20,469 Coal Tons 279 500 — — 1,500 Natural Gas MMBtus 421 286 — — — Heating Oil and Gasoline Gallons 1,089 521 1,108 614 699 Interest Rate USD $ 5,094 $ 3,455 $ — $ — $ —
Cash Collateral Netting	June 30, 2015 December 31, 2014 Company Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities Cash Collateral Received Netted Against Risk Management Assets Cash Collateral Paid Netted Against Risk Management Liabilities (in thousands) APCo $ — $ 915 $ 68 $ 98 I&M — 428 163 47 OPCo — 121 — 102 PSO — 115 — 54 SWEPCo — 134 — 62
Fair Value of Derivative Instruments	SWEPCo Fair Value of Derivative Instruments June 30, 2015 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 2,183 $ — $ — $ 2,183 $ (106 ) $ 2,077 Long-term Risk Management Assets 33 — — 33 — 33 Total Assets 2,216 — — 2,216 (106 ) 2,110 Current Risk Management Liabilities 2,763 — — 2,763 (240 ) 2,523 Long-term Risk Management Liabilities — — — — — — Total Liabilities 2,763 — — 2,763 (240 ) 2,523 Total MTM Derivative Contract Net Assets (Liabilities) $ (547 ) $ — $ — $ (547 ) $ 134 $ (413 ) SWEPCo Fair Value of Derivative Instruments December 31, 2014 Risk Management Contracts Hedging Contracts Gross Amounts of Risk Management Assets/ Liabilities Recognized Gross Amounts Offset in the Statement of Financial Position (b) Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position (c) Balance Sheet Location Commodity (a) Commodity (a) Interest Rate and Foreign Currency (a) (in thousands) Current Risk Management Assets $ 471 $ — $ — $ 471 $ (440 ) $ 31 Long-term Risk Management Assets — — — — — — Total Assets 471 — — 471 (440 ) 31 Current Risk Management Liabilities 1,584 — — 1,584 (502 ) 1,082 Long-term Risk Management Liabilities — — — — — — Total Liabilities 1,584 — — 1,584 (502 ) 1,082 Total MTM Derivative Contract Net Assets (Liabilities) $ (1,113 ) $ — $ — $ (1,113 ) $ 62 $ (1,051 ) (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 June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 480 $ 619 $ 35 $ 35 $ 43 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (80 ) (58 ) (111 ) (76 ) (99 ) Maintenance Expense (133 ) (55 ) (114 ) (79 ) (84 ) Purchased Electricity for Resale 11 38 — — — Regulatory Assets (a) 558 328 — 954 2,111 Regulatory Liabilities (a) 26,809 8,415 (7,272 ) 6,242 9,350 Total Gain (Loss) on Risk Management Contracts $ 28,000 $ 10,292 $ (7,462 ) $ 7,076 $ 11,321 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Three Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,184 $ 1,323 $ 56 $ 63 $ (79 ) Sales to AEP Affiliates — (300 ) — 300 — Regulatory Assets (a) — — — (12 ) (16 ) Regulatory Liabilities (a) 13,718 8,793 6,404 (669 ) (1,019 ) Total Gain (Loss) on Risk Management Contracts $ 14,902 $ 9,816 $ 6,460 $ (318 ) $ (1,114 ) Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2015 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 1,158 $ 3,241 $ 35 $ 24 $ 26 Sales to AEP Affiliates 355 1,005 — — — Other Operation Expense (199 ) (158 ) (261 ) (198 ) (246 ) Maintenance Expense (338 ) (135 ) (257 ) (160 ) (177 ) Purchased Electricity for Resale 740 332 — — — Regulatory Assets (a) 1,275 (232 ) — 805 (1,422 ) Regulatory Liabilities (a) 28,600 5,839 (2,599 ) 5,575 13,309 Total Gain (Loss) on Risk Management Contracts $ 31,591 $ 9,892 $ (3,082 ) $ 6,046 $ 11,490 Amount of Gain (Loss) Recognized on Risk Management Contracts For the Six Months Ended June 30, 2014 Location of Gain (Loss) APCo I&M OPCo PSO SWEPCo (in thousands) Electric Generation, Transmission and Distribution Revenues $ 6,031 $ 7,479 $ 56 $ 127 $ (56 ) Sales to AEP Affiliates — (521 ) — 521 — Regulatory Assets (a) 4 — — (10 ) (13 ) Regulatory Liabilities (a) 46,050 27,110 41,503 (189 ) 311 Total Gain on Risk Management Contracts $ 52,085 $ 34,068 $ 41,559 $ 449 $ 242 (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 June 30, 2015 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 4,027 I&M — — — — — (13,871 ) OPCo — — — — — 4,916 PSO — — — — — 4,563 SWEPCo — — — — — (9,902 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate and Foreign Currency Maximum Term for Exposure to Variability of Future Cash Flows (in thousands) (in months) APCo $ — $ 773 0 I&M — (1,214 ) 0 OPCo — 1,350 0 PSO — 759 0 SWEPCo — (1,728 ) 0 Impact of Cash Flow Hedges on the Registrant Subsidiaries’ Condensed Balance Sheets December 31, 2014 Hedging Assets (a) Hedging Liabilities (a) AOCI Gain (Loss) Net of Tax Company Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency Commodity Interest Rate and Foreign Currency (in thousands) APCo $ — $ — $ — $ — $ — $ 3,896 I&M — — — — — (14,406 ) OPCo — — — — — 5,602 PSO — — — — — 4,943 SWEPCo — — — — — (11,036 ) Expected to be Reclassified to Net Income During the Next Twelve Months Company Commodity Interest Rate Currency (in thousands) APCo $ — $ 275 I&M — (1,090 ) OPCo — 1,372 PSO — 759 SWEPCo — (1,998 ) (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	June 30, 2015 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 3,211 $ 987 I&M — — 2,178 215 OPCo — — — — PSO — — 244 6,783 SWEPCo — — 293 210 December 31, 2014 Amount of Collateral the Registrant Subsidiaries Would Have Been Required Fair Value to Post for Derivative Amount of Collateral Amount of of Contracts Contracts as well as Non- the Registrant Subsidiaries Collateral with Credit Derivative Contracts Subject Would Have Been Required Attributable to Downgrade to the Same Master Netting to Post Attributable to Other Company Triggers Arrangement RTOs and ISOs Contracts (in thousands) APCo $ — $ — $ 6,339 $ 74 I&M — — 4,299 47 OPCo — — — — PSO — — 693 4,111 SWEPCo — — 877 166
Liabilities Subject to Cross Default Provisions	June 30, 2015 Liabilities for Additional Contracts with Cross Settlement Default Provisions Liability if Cross Prior to Contractual Amount of Cash Default Provision Company Netting Arrangements Collateral Posted is Triggered (in thousands) APCo $ 6,795 $ — $ 6,715 I&M 4,609 — 4,554 OPCo — — — PSO — — — SWEPCo — — — December 31, 2014 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 $ 9,043 $ — $ 9,012 I&M 6,134 — 6,113 OPCo — — — PSO — — — SWEPCo — — —

Fair Value Measurements (Tables

Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2015
Book Values and Fair Values of Long-term Debt	June 30, 2015 December 31, 2014 Book Value Fair Value Book Value Fair Value (in millions) Long-term Debt $ 19,578 $ 21,205 $ 18,684 $ 21,075
Other Temporary Investments	June 30, 2015 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 249 $ — $ — $ 249 Fixed Income Securities – Mutual Funds 81 — — 81 Equity Securities – Mutual Funds 13 13 — 26 Total Other Temporary Investments $ 343 $ 13 $ — $ 356 December 31, 2014 Other Temporary Investments Cost Gross Gains Gross Losses Fair Value (in millions) Restricted Cash (a) $ 280 $ — $ — $ 280 Fixed Income Securities – Mutual Funds 81 — — 81 Equity Securities – Mutual Funds 13 12 — 25 Total Other Temporary Investments $ 374 $ 12 $ — $ 386 (a) Primarily represents amounts held for the repayment of debt.
Debt and Equity Securities Within Other Temporary Investments	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in millions) Proceeds from Investment Sales $ — $ — $ — $ — Purchases of Investments — — — 1 Gross Realized Gains on Investment Sales — — — — Gross Realized Losses on Investment Sales — — — —
Nuclear Trust Fund Investments	June 30, 2015 December 31, 2014 Fair Value Gross Unrealized Gains Other-Than- Temporary Fair Value Gross Unrealized Gains Other-Than- Temporary (in millions) Cash and Cash Equivalents $ 53 $ — $ — $ 20 $ — $ — Fixed Income Securities: United States Government 786 37 (3 ) 697 45 (5 ) Corporate Debt 62 3 (1 ) 48 4 (1 ) State and Local Government 70 1 — 208 1 — Subtotal Fixed Income Securities 918 41 (4 ) 953 50 (6 ) Equity Securities – Domestic 1,135 595 (78 ) 1,123 599 (79 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106 $ 636 $ (82 ) $ 2,096 $ 649 $ (85 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in millions) Proceeds from Investment Sales $ 288 $ 335 $ 516 $ 483 Purchases of Investments 295 345 541 509 Gross Realized Gains on Investment Sales 8 9 19 17 Gross Realized Losses on Investment Sales 6 8 10 9
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Securities (in millions) Within 1 year $ 141 1 year – 5 years 376 5 years – 10 years 186 After 10 years 215 Total $ 918
Fair Value, Assets and Liabilities Measured on Recurring Basis	Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17 $ 6 $ — $ 172 $ 195 Other Temporary Investments Restricted Cash (a) 205 7 — 37 249 Fixed Income Securities - Mutual Funds 81 — — — 81 Equity Securities – Mutual Funds (b) 26 — — — 26 Total Other Temporary Investments 312 7 — 37 356 Risk Management Assets Risk Management Commodity Contracts (c) (d) 23 524 269 (293 ) 523 Cash Flow Hedges: Commodity Hedges (c) — 24 1 (15 ) 10 Fair Value Hedges — — — 2 2 Total Risk Management Assets 23 548 270 (306 ) 535 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 42 — — 11 53 Fixed Income Securities: United States Government — 786 — — 786 Corporate Debt — 62 — — 62 State and Local Government — 70 — — 70 Subtotal Fixed Income Securities — 918 — — 918 Equity Securities – Domestic (b) 1,135 — — — 1,135 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177 918 — 11 2,106 Total Assets $ 1,529 $ 1,479 $ 270 $ (86 ) $ 3,192 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (d) $ 38 $ 444 $ 62 $ (317 ) $ 227 Cash Flow Hedges: Commodity Hedges (c) — 29 5 (15 ) 19 Interest Rate/Foreign Currency Hedges — 1 — — 1 Fair Value Hedges — 3 — 2 5 Total Risk Management Liabilities $ 38 $ 477 $ 67 $ (330 ) $ 252 Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in millions) Cash and Cash Equivalents (a) $ 17 $ 1 $ — $ 145 $ 163 Other Temporary Investments Restricted Cash (a) 234 9 — 37 280 Fixed Income Securities - Mutual Funds 81 — — — 81 Equity Securities – Mutual Funds (b) 25 — — — 25 Total Other Temporary Investments 340 9 — 37 386 Risk Management Assets Risk Management Commodity Contracts (c) (f) 37 528 190 (302 ) 453 Cash Flow Hedges: Commodity Hedges (c) — 32 — (16 ) 16 Fair Value Hedges — 1 — 2 3 Total Risk Management Assets 37 561 190 (316 ) 472 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (e) 9 — — 11 20 Fixed Income Securities: United States Government — 697 — — 697 Corporate Debt — 48 — — 48 State and Local Government — 208 — — 208 Subtotal Fixed Income Securities — 953 — — 953 Equity Securities – Domestic (b) 1,123 — — — 1,123 Total Spent Nuclear Fuel and Decommissioning Trusts 1,132 953 — 11 2,096 Total Assets $ 1,526 $ 1,524 $ 190 $ (123 ) $ 3,117 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (c) (f) $ 65 $ 432 $ 36 $ (334 ) $ 199 Cash Flow Hedges: Commodity Hedges (c) — 27 3 (16 ) 14 Interest Rate/Foreign Currency Hedges — 1 — — 1 Fair Value Hedges — 7 — 2 9 Total Risk Management Liabilities $ 65 $ 467 $ 39 $ (348 ) $ 223 (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 June 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($5) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $16 million in 2015 , $53 million in periods 2016-2018, $8 million in periods 2019-2020 and $3 million in periods 2021-2032; Level 3 matures $33 million in 2015 , $59 million in periods 2016-2018, $22 million in periods 2019-2020 and $93 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts. (e) Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds. (f) The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015 , $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015 , $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts.
Changes in Fair Value of Net Trading Derivatives and Other Investments	Three Months Ended June 30, 2015 Net Risk Management Assets (Liabilities) (in millions) Balance as of March 31, 2015 $ 131 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 2 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 12 Purchases, Issuances and Settlements (c) (16 ) Transfers into Level 3 (d) (e) 42 Transfers out of Level 3 (e) (f) (2 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 34 Balance as of June 30, 2015 $ 203 Three Months Ended June 30, 2014 Net Risk Management (in millions) Balance as of March 31, 2014 $ 105 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (14 ) Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 6 Purchases, Issuances and Settlements (c) (2 ) Transfers into Level 3 (d) (e) 5 Transfers out of Level 3 (e) (f) (6 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 38 Balance as of June 30, 2014 $ 132 Six Months Ended June 30, 2015 Net Risk Management (in millions) Balance as of December 31, 2014 $ 151 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 12 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) 51 Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income (2 ) Purchases, Issuances and Settlements (c) (54 ) Transfers into Level 3 (d) (e) 21 Transfers out of Level 3 (e) (f) (14 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 38 Balance as of June 30, 2015 $ 203 Six Months Ended June 30, 2014 Net Risk Management (in millions) Balance as of December 31, 2013 $ 117 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 82 Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date (a) (9 ) Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income 14 Purchases, Issuances and Settlements (c) (102 ) Transfers into Level 3 (d) (e) 1 Transfers out of Level 3 (e) (f) (7 ) Changes in Fair Value Allocated to Regulated Jurisdictions (g) 36 Balance as of June 30, 2014 $ 132 (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 June 30, 2015 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 232 $ 65 Discounted Cash Flow Forward Market Price (a) $ 13.50 $ 163.52 $ 37.79 Counterparty Credit Risk (b) 328 FTRs 38 2 Discounted Cash Flow Forward Market Price (a) (8.00 ) 9.87 1.37 Total $ 270 $ 67 Significant Unobservable Inputs December 31, 2014 Significant Input/Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input Low High Average (in millions) Energy Contracts $ 157 $ 37 Discounted Cash Flow Forward Market Price (a) $ 11.37 $ 159.92 $ 57.18 Counterparty Credit Risk (b) 303 FTRs 33 2 Discounted Cash Flow Forward Market Price (a) (14.63 ) 20.02 0.96 Total $ 190 $ 39 (a) Represents market prices in dollars per MWh. (b) Represents average price of credit default swaps used to calculate counterparty credit risk, reported in basis points.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher) Counterparty Credit Risk Loss Increase (Decrease) Higher (Lower) Counterparty Credit Risk Gain Increase (Decrease) Lower (Higher)
Appalachian Power Co [Member]
Book Values and Fair Values of Long-term Debt	June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639
Nuclear Trust Fund Investments	June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046
Fair Value, Assets and Liabilities Measured on Recurring Basis	APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long-term Debt	June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639
Nuclear Trust Fund Investments	June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046
Fair Value, Assets and Liabilities Measured on Recurring Basis	APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
Ohio Power Co [Member]
Book Values and Fair Values of Long-term Debt	June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639
Nuclear Trust Fund Investments	June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046
Fair Value, Assets and Liabilities Measured on Recurring Basis	APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long-term Debt	June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639
Nuclear Trust Fund Investments	June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046
Fair Value, Assets and Liabilities Measured on Recurring Basis	APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long-term Debt	June 30, 2015 December 31, 2014 Company Book Value Fair Value Book Value Fair Value (in thousands) APCo $ 3,966,647 $ 4,396,429 $ 3,980,274 $ 4,711,210 I&M 2,088,913 2,264,196 2,027,397 2,255,124 OPCo 2,189,159 2,515,960 2,297,123 2,709,452 PSO 1,290,995 1,417,359 1,041,036 1,216,205 SWEPCo 2,435,478 2,600,476 2,140,437 2,402,639
Nuclear Trust Fund Investments	June 30, 2015 December 31, 2014 Gross Other-Than- Gross Other-Than- Fair Unrealized Temporary Fair Unrealized Temporary Value Gains Impairments Value Gains Impairments (in thousands) Cash and Cash Equivalents $ 52,861 $ — $ — $ 19,966 $ — $ — Fixed Income Securities: United States Government 786,222 37,318 (2,613 ) 697,042 44,615 (5,016 ) Corporate Debt 61,654 2,851 (1,115 ) 47,792 4,523 (1,018 ) State and Local Government 70,170 992 (374 ) 208,553 1,206 (319 ) Subtotal Fixed Income Securities 918,046 41,161 (4,102 ) 953,387 50,344 (6,353 ) Equity Securities - Domestic 1,135,183 594,609 (78,256 ) 1,122,379 598,788 (79,142 ) Spent Nuclear Fuel and Decommissioning Trusts $ 2,106,090 $ 635,770 $ (82,358 ) $ 2,095,732 $ 649,132 $ (85,495 )
Securities Activity Within the Decommissioning and SNF Trusts	Three Months Ended June 30, Six Months Ended June 30, 2015 2014 2015 2014 (in thousands) Proceeds from Investment Sales $ 287,620 $ 334,834 $ 515,784 $ 482,534 Purchases of Investments 294,870 344,324 540,711 508,835 Gross Realized Gains on Investment Sales 7,657 9,077 18,810 17,218 Gross Realized Losses on Investment Sales 5,885 7,834 9,656 8,708
Contractual Maturities, Fair Value of Debt Securities in Nuclear Trusts	Fair Value of Fixed Income Securities (in thousands) Within 1 year $ 140,990 1 year – 5 years 375,637 5 years – 10 years 186,505 After 10 years 214,914 Total $ 918,046
Fair Value, Assets and Liabilities Measured on Recurring Basis	APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,565 $ — $ — $ 18 $ 15,583 Risk Management Assets Risk Management Commodity Contracts (b) (c) 176 20,754 34,210 (13,261 ) 41,879 Total Assets: $ 15,741 $ 20,754 $ 34,210 $ (13,243 ) $ 57,462 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 197 $ 24,212 $ 374 $ (14,176 ) $ 10,607 APCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 15,599 $ — $ — $ 33 $ 15,632 Risk Management Assets Risk Management Commodity Contracts (b) (c) 206 20,197 17,654 (9,374 ) 28,683 Total Assets: $ 15,805 $ 20,197 $ 17,654 $ (9,341 ) $ 44,315 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 227 $ 20,339 $ 1,912 $ (9,404 ) $ 13,074 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 119 $ 15,428 $ 12,710 $ (9,717 ) $ 18,540 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 41,818 — — 11,043 52,861 Fixed Income Securities: United States Government — 786,222 — — 786,222 Corporate Debt — 61,654 — — 61,654 State and Local Government — 70,170 — — 70,170 Subtotal Fixed Income Securities — 918,046 — — 918,046 Equity Securities - Domestic (e) 1,135,183 — — — 1,135,183 Total Spent Nuclear Fuel and Decommissioning Trusts 1,177,001 918,046 — 11,043 2,106,090 Total Assets $ 1,177,120 $ 933,474 $ 12,710 $ 1,326 $ 2,124,630 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 133 $ 14,621 $ 866 $ (10,145 ) $ 5,475 I&M Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 140 $ 15,893 $ 16,008 $ (6,396 ) $ 25,645 Spent Nuclear Fuel and Decommissioning Trusts Cash and Cash Equivalents (d) 9,418 — — 10,548 19,966 Fixed Income Securities: United States Government — 697,042 — — 697,042 Corporate Debt — 47,792 — — 47,792 State and Local Government — 208,553 — — 208,553 Subtotal Fixed Income Securities — 953,387 — — 953,387 Equity Securities - Domestic (e) 1,122,379 — — — 1,122,379 Total Spent Nuclear Fuel and Decommissioning Trusts 1,131,797 953,387 — 10,548 2,095,732 Total Assets $ 1,131,937 $ 969,280 $ 16,008 $ 4,152 $ 2,121,377 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 154 $ 11,440 $ 1,304 $ (6,280 ) $ 6,618 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ 121 $ 42,474 $ 1,461 $ 44,056 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 426 $ 4,817 $ 1,340 $ 6,583 OPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Restricted Cash for Securitized Funding (a) $ 408 $ — $ — $ 28,288 $ 28,696 Risk Management Assets Risk Management Commodity Contracts (b) (c) — — 52,343 1 52,344 Total Assets $ 408 $ — $ 52,343 $ 28,289 $ 81,040 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 1,116 $ 3,941 $ (101 ) $ 4,956 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ 2 $ 98 $ 1,750 $ (90 ) $ 1,760 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 5 $ 278 $ 51 $ (205 ) $ 129 PSO Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Risk Management Assets Risk Management Commodity Contracts (b) (c) $ — $ — $ 360 $ (360 ) $ — Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 595 $ 737 $ (414 ) $ 918 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis June 30, 2015 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 6,391 $ — $ — $ 1,626 $ 8,017 Risk Management Assets Risk Management Commodity Contracts (b) (c) 3 114 2,100 (107 ) 2,110 Total Assets $ 6,394 $ 114 $ 2,100 $ 1,519 $ 10,127 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ 6 $ 2,697 $ 61 $ (241 ) $ 2,523 SWEPCo Assets and Liabilities Measured at Fair Value on a Recurring Basis December 31, 2014 Level 1 Level 2 Level 3 Other Total Assets: (in thousands) Cash and Cash Equivalents (a) $ 12,660 $ — $ — $ 1,696 $ 14,356 Risk Management Assets Risk Management Commodity Contracts (b) (c) — 31 439 (439 ) 31 Total Assets $ 12,660 $ 31 $ 439 $ 1,257 $ 14,387 Liabilities: Risk Management Liabilities Risk Management Commodity Contracts (b) (c) $ — $ 684 $ 899 $ (501 ) $ 1,082 (a) Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds. (b) 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.” (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 June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2015 $ 5,987 $ 5,573 $ 45,942 $ (685 ) $ (1,222 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (1,380 ) (802 ) 638 766 4,173 Purchases, Issuances and Settlements (c) (1,606 ) (2,264 ) (1,691 ) (81 ) (2,951 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 29,668 8,545 (7,232 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Three Months Ended June 30, 2014 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of March 31, 2014 $ 7,401 $ 4,842 $ 3,912 $ 349 $ 442 Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) (4,046 ) (2,554 ) (4,236 ) (349 ) (442 ) Purchases, Issuances and Settlements (c) (32 ) (35 ) 347 — — Transfers into Level 3 (d) (e) 182 124 — — — Transfers out of Level 3 (e) (f) 3 2 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,886 10,544 9,277 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) Six Months Ended June 30, 2015 APCo I&M OPCo PSO SWEPCo (in thousands) Balance as of December 31, 2014 $ 15,742 $ 14,704 $ 48,402 $ (377 ) $ (460 ) Realized Gain (Loss) Included in Net Income (or Changes in Net Assets) (a) (b) 1,230 (825 ) 1,548 (176 ) 9,187 Purchases, Issuances and Settlements (c) (14,964 ) (11,319 ) (8,368 ) 553 (8,727 ) Transfers out of Level 3 (e) (f) 1,167 792 — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 30,661 8,492 (3,925 ) 1,699 2,039 Balance as of June 30, 2015 $ 33,836 $ 11,844 $ 37,657 $ 1,699 $ 2,039 Six Months Ended June 30, 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) 29,132 18,211 30,768 — — Purchases, Issuances and Settlements (c) (31,790 ) (20,014 ) (33,688 ) — — Transfers into Level 3 (d) (e) (3,643 ) (2,471 ) — — — Transfers out of Level 3 (e) (f) (2 ) (2 ) — — — Changes in Fair Value Allocated to Regulated Jurisdictions (g) 14,135 10,035 9,300 (3 ) (3 ) Balance as of June 30, 2014 $ 18,394 $ 12,923 $ 9,300 $ (3 ) $ (3 ) (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 June 30, 2015 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 10,570 $ 183 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 23,640 191 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 34,210 $ 374 Significant Unobservable Inputs December 31, 2014 APCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 5,801 $ 1,799 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 11,853 113 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 17,654 $ 1,912 Significant Unobservable Inputs June 30, 2015 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 9,184 $ 116 Discounted Cash Flow Forward Market Price $ 15.36 $ 56.30 $ 35.88 FTRs 3,526 750 Discounted Cash Flow Forward Market Price (6.16 ) 9.87 1.57 Total $ 12,710 $ 866 Significant Unobservable Inputs December 31, 2014 I&M Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 6,375 $ 1,219 Discounted Cash Flow Forward Market Price $ 13.43 $ 123.02 $ 52.47 FTRs 9,633 85 Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 Total $ 16,008 $ 1,304 Significant Unobservable Inputs June 30, 2015 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 42,474 $ 4,817 Discounted Cash Flow Forward Market Price $ 42.89 $ 163.52 $ 91.51 Significant Unobservable Inputs December 31, 2014 OPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) Energy Contracts $ 45,101 $ 3,941 Discounted Cash Flow Forward Market Price $ 48.25 $ 159.92 $ 84.04 FTRs 7,242 — Discounted Cash Flow Forward Market Price (14.63 ) 20.02 1.01 $ 52,343 $ 3,941 Significant Unobservable Inputs June 30, 2015 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 1,750 $ 51 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 PSO Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 360 $ 737 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 Significant Unobservable Inputs June 30, 2015 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 2,100 $ 61 Discounted Cash Flow Forward Market Price $ (6.16 ) $ 9.87 $ 1.57 Significant Unobservable Inputs December 31, 2014 SWEPCo Significant Forward Price Range Fair Value Valuation Unobservable Weighted Assets Liabilities Technique Input (a) Low High Average (in thousands) FTRs $ 439 $ 899 Discounted Cash Flow Forward Market Price $ (14.63 ) $ 20.02 $ 1.01 (a) Represents market prices in dollars per MWh.
Sensitivity of Fair Value Measurements	Sensitivity of Fair Value Measurements June 30, 2015 Significant Unobservable Input Position Change in Input Impact on Fair Value Measurement Forward Market Price Buy Increase (Decrease) Higher (Lower) Forward Market Price Sell Increase (Decrease) Lower (Higher)

Financing Activities (Tables)

Financing Activities (Tables)	6 Months Ended
	Jun. 30, 2015
Long-term Debt	Type of Debt June 30, 2015 December 31, 2014 (in millions) Senior Unsecured Notes $ 13,628 $ 12,647 Pollution Control Bonds 1,963 1,963 Notes Payable 409 357 Securitization Bonds 2,200 2,380 Spent Nuclear Fuel Obligation (a) 266 266 Other Long-term Debt 1,144 1,101 Fair Value of Interest Rate Hedges (3 ) (6 ) Unamortized Discount, Net (29 ) (24 ) Total Long-term Debt Outstanding 19,578 18,684 Long-term Debt Due Within One Year 1,817 2,503 Long-term Debt $ 17,761 $ 16,181 (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 June 30, 2015 and December 31, 2014 , respectively, and are included in Spent Nuclear Fuel and Decommissioning Trusts on our condensed balance sheets.
Long-term Debt Issuances	Company Type of Debt Principal Amount Interest Rate Due Date Issuances: (in millions) (%) APCo Pollution Control Bonds $ 86 1.90 2019 APCo Senior Unsecured Notes 350 4.45 2045 APCo Senior Unsecured Notes 300 3.40 2025 I&M Notes Payable 111 Variable 2019 I&M Other Long-term Debt 100 Variable 2018 PSO Senior Unsecured Notes 125 3.17 2025 PSO Senior Unsecured Notes 125 4.09 2045 SWEPCo Pollution Control Bonds 54 1.60 2019 SWEPCo Senior Unsecured Notes 400 3.90 2045 Non-Registrant: AEPTCo Senior Unsecured Notes 60 4.01 2030 AEPTCo Senior Unsecured Notes 50 3.66 2025 AEPTCo Senior Unsecured Notes 40 3.76 2025 AGR Other Long-term Debt 500 Variable 2017 KPCo Other Long-term Debt 25 Variable 2018 Transource Missouri Other Long-term Debt 13 Variable 2018 WPCo Senior Unsecured Notes 113 3.36 2022 WPCo Senior Unsecured Notes 122 3.70 2025 WPCo Senior Unsecured Notes 50 4.20 2035 Total Issuances $ 2,624 (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 issuance amount.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Due Date Total Retirements and Principal Payments: (in millions) (%) APCo Securitization Bonds $ 11 2.008 2024 APCo Senior Unsecured Notes 350 7.95 2020 APCo Senior Unsecured Notes 300 3.40 2015 I&M Other Long-term Debt 94 Variable 2015 I&M Notes Payable 18 Variable 2016 I&M Notes Payable 14 Variable 2017 I&M Notes Payable 16 Variable 2019 I&M Notes Payable 6 Variable 2019 I&M Notes Payable 1 Variable 2016 I&M Notes Payable 1 2.12 2016 OPCo Pollution Control Bonds 86 3.125 2015 OPCo Securitization Bonds 22 0.958 2018 SWEPCo Notes Payable 2 4.58 2032 SWEPCo Pollution Control Bonds 54 3.25 2015 SWEPCo Senior Unsecured Notes 100 5.375 2015 Non-Registrant: AEGCo Senior Unsecured Notes 4 6.33 2037 AEP Subsidiaries Notes Payable 1 Variable 2017 AGR Other Long-term Debt 500 Variable 2015 TCC Securitization Bonds 78 5.09 2015 TCC Securitization Bonds 42 6.25 2016 TCC Securitization Bonds 27 0.88 2017 Total Retirements and Principal Payments $ 1,727
Short Term Debt	June 30, 2015 December 31, 2014 Type of Debt Outstanding Amount Interest Rate (a) Outstanding Interest (in millions) (in millions) Securitized Debt for Receivables (b) $ 708 0.27 % $ 744 0.22 % Commercial Paper 397 0.47 % 602 0.59 % Total Short-term Debt $ 1,105 $ 1,346 (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 Six Months Ended 2015 2014 2015 2014 (dollars in millions) Effective Interest Rates on Securitization of Accounts Receivable 0.27 % 0.22 % 0.27 % 0.23 % Net Uncollectible Accounts Receivable Written Off $ 6 $ 7 $ 13 $ 14
Customer Accounts Receivable Managed Portfolio	June 30, 2015 December 31, 2014 (in millions) Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts $ 977 $ 975 Total Principal Outstanding 708 744 Delinquent Securitized Accounts Receivable 50 44 Bad Debt Reserves Related to Securitization/Sale of Accounts Receivable 19 13 Unbilled Receivables Related to Securitization/Sale of Accounts Receivable 363 335
Appalachian Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — %
Accounts Receivable and Accrued Unbilled Revenues	June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497
Indiana Michigan Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — %
Accounts Receivable and Accrued Unbilled Revenues	June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497
Ohio Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — %
Accounts Receivable and Accrued Unbilled Revenues	June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497
Public Service Co Of Oklahoma [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — %
Accounts Receivable and Accrued Unbilled Revenues	June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497
Southwestern Electric Power Co [Member]
Long-term Debt Issuances	Company Type of Debt Principal Amount (a) Interest Rate Due Date Issuances: (in thousands) (%) APCo Pollution Control Bonds $ 86,000 1.90 2019 APCo Senior Unsecured Notes 350,000 4.45 2045 APCo Senior Unsecured Notes 300,000 3.40 2025 I&M Notes Payable 111,300 Variable 2019 I&M Other Long-term Debt 100,000 Variable 2018 PSO Senior Unsecured Notes 125,000 3.17 2025 PSO Senior Unsecured Notes 125,000 4.09 2045 SWEPCo Pollution Control Bonds 53,500 1.60 2019 SWEPCo Senior Unsecured Notes 400,000 3.90 2045 (a) Amounts indicated on the statements of cash flows are net of issuance costs and premium or discount and will not tie to the issuance amounts.
Retirements and Principal Payments	Company Type of Debt Principal Amount Paid Interest Rate Due Date Retirements and Principal Payments: (in thousands) (%) APCo Land Note $ 18 13.718 2026 APCo Notes Payable - Affiliated 86,000 3.125 2015 APCo Securitization Bonds 11,037 2.008 2024 APCo Senior Unsecured Notes 350,000 7.95 2020 APCo Senior Unsecured Notes 300,000 3.40 2015 I&M Notes Payable 18,600 Variable 2016 I&M Notes Payable 13,659 Variable 2017 I&M Notes Payable 16,501 Variable 2019 I&M Notes Payable 5,834 Variable 2019 I&M Notes Payable 844 Variable 2016 I&M Notes Payable 585 2.12 2016 I&M Other Long-term Debt 93,500 Variable 2015 I&M Other Long-term Debt 554 6.00 2025 OPCo Other Long-term Debt 38 1.149 2028 OPCo Pollution Control Bonds 86,000 3.125 2015 OPCo Securitization Bonds 22,200 0.958 2018 PSO Other Long-term Debt 212 3.00 2027 SWEPCo Notes Payable 1,625 4.58 2032 SWEPCo Pollution Control Bonds 53,500 3.25 2015 SWEPCo Senior Unsecured Notes 100,000 5.375 2015
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits	Maximum Average Net Loans to Borrowings Maximum Borrowings Average (Borrowings from) Authorized from the Loans to the from the Loans to the the Utility Money Short-term Utility Utility Utility Utility Pool as of Borrowing Company Money Pool Money Pool Money Pool Money Pool June 30, 2015 Limit (in thousands) APCo $ 82,417 $ 694,785 $ 58,723 $ 133,887 $ (33,703 ) $ 600,000 I&M 200,032 13,515 141,520 13,501 (127,154 ) 500,000 OPCo — 367,472 — 273,487 187,812 400,000 PSO 165,947 95,472 113,117 51,855 64,212 300,000 SWEPCo 112,481 299,932 52,596 170,502 179,709 350,000
Maximum and Minimum Interest Rates for Funds Either Borrowed from or Loaned to Utility Money Pool	Six Months Ended June 30, 2015 2014 Maximum Interest Rate 0.59 % 0.33 % Minimum Interest Rate 0.39 % 0.24 %
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool	Average Interest Rate for Funds Borrowed from the Utility Money Pool for Average Interest Rate for Funds Loaned to the Utility Money Pool for Six Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 APCo 0.45 % 0.26 % 0.46 % 0.29 % I&M 0.47 % 0.26 % 0.47 % 0.30 % OPCo — % 0.27 % 0.47 % 0.29 % PSO 0.49 % 0.28 % 0.47 % — % SWEPCo 0.46 % 0.28 % 0.49 % — %
Accounts Receivable and Accrued Unbilled Revenues	June 30, December 31, Company 2015 2014 (in thousands) APCo $ 139,005 $ 159,823 I&M 145,633 137,459 OPCo 366,098 365,834 PSO 131,940 112,905 SWEPCo 163,994 148,668
Fees Paid to AEP Credit for Customer Accounts Receivable Sold	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 1,573 $ 2,037 $ 4,027 $ 4,460 I&M 2,063 1,785 4,420 3,825 OPCo 6,668 6,647 14,683 14,145 PSO 1,324 1,349 2,746 2,672 SWEPCo 1,625 1,579 3,347 3,145
Proceeds on Sale of Receivables to AEP Credit	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 330,593 $ 345,963 $ 760,217 $ 783,159 I&M 371,058 353,030 790,619 760,180 OPCo 563,381 626,025 1,278,365 1,312,652 PSO 311,885 325,536 614,386 615,753 SWEPCo 381,100 420,909 754,267 811,497

Variable Interest Entities (Tab

Variable Interest Entities (Tables)	6 Months Ended
	Jun. 30, 2015
Consolidated Assets and Liabilities of Variable Interest Entities	AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES June 30, 2015 (in millions) SWEPCo Sabine I&M DCC Fuel AEP Credit TCC Transition Funding OPCo Ohio Phase-in- Recovery Funding APCo Appalachian Consumer Rate Relief Funding Protected Cell of EIS Transource Energy ASSETS Current Assets $ 58 $ 114 $ 986 $ 220 $ 33 $ 19 $ 155 $ 10 Net Property, Plant and Equipment 142 220 — — — — — 137 Other Noncurrent Assets 60 118 — 1,533 (a) 186 (b) 347 (c) 1 5 Total Assets $ 260 $ 452 $ 986 $ 1,753 $ 219 $ 366 $ 156 $ 152 LIABILITIES AND EQUITY Current Liabilities $ 28 $ 109 $ 886 $ 326 $ 47 $ 27 $ 43 $ 28 Noncurrent Liabilities 232 343 — 1,409 171 337 67 70 Equity — — 100 18 1 2 46 54 Total Liabilities and Equity $ 260 $ 452 $ 986 $ 1,753 $ 219 $ 366 $ 156 $ 152 (a) Includes an intercompany item eliminated in consolidation of $72 million . (b) Includes an intercompany item eliminated in consolidation of $87 million . (c) Includes an intercompany item eliminated in consolidation of $4 million . AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES VARIABLE INTEREST ENTITIES December 31, 2014 (in millions) SWEPCo Sabine I&M DCC Fuel AEP Credit TCC Transition Funding OPCo Ohio Phase-in- Recovery Funding APCo Appalachian Consumer Rate Relief Funding Protected Cell of EIS Transource Energy ASSETS Current Assets $ 68 $ 97 $ 980 $ 239 $ 33 $ 18 $ 149 $ 2 Net Property, Plant and Equipment 145 158 — — — — — 98 Other Noncurrent Assets 52 80 — 1,654 (a) 210 (b) 358 (c) 2 4 Total Assets $ 265 $ 335 $ 980 $ 1,893 $ 243 $ 376 $ 151 $ 104 LIABILITIES AND EQUITY Current Liabilities $ 36 $ 86 $ 894 $ 322 $ 47 $ 27 $ 44 $ 21 Noncurrent Liabilities 228 249 — 1,553 195 347 62 55 Equity 1 — 86 18 1 2 45 28 Total Liabilities and Equity $ 265 $ 335 $ 980 $ 1,893 $ 243 $ 376 $ 151 $ 104 (a) Includes an intercompany item eliminated in consolidation of $75 million . (b) Includes an intercompany item eliminated in consolidation of $97 million . (c) Includes an intercompany item eliminated in consolidation of $4 million .
Appalachian Power Co [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741
Appalachian Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772
Indiana Michigan Power Co [Member] | Billings from AEP Generating Co [Member]
Billings from Significant Variable Interest	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) I&M $ 59,993 $ 65,190 $ 114,958 $ 135,612
Indiana Michigan Power Co [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741
Indiana Michigan Power Co [Member] | Carrying Amount in AEGCo's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) I&M $ 21,084 $ 21,084 $ 20,031 $ 20,031
Indiana Michigan Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772
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 June 30, 2015 and December 31, 2014 (in thousands) DCC Fuel ASSETS 2015 2014 Current Assets $ 114,522 $ 97,361 Net Property, Plant and Equipment 219,786 158,121 Other Noncurrent Assets 117,702 79,705 Total Assets $ 452,010 $ 335,187 LIABILITIES AND EQUITY Current Liabilities $ 109,491 $ 86,026 Noncurrent Liabilities 342,519 249,161 Total Liabilities and Equity $ 452,010 $ 335,187
Ohio Power Co [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741
Ohio Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772
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 June 30, 2015 and December 31, 2014 (in thousands) Ohio Phase-In Recovery Funding ASSETS 2015 2014 Current Assets $ 32,778 $ 32,676 Other Noncurrent Assets (a) 186,609 209,922 Total Assets $ 219,387 $ 242,598 LIABILITIES AND EQUITY Current Liabilities $ 47,539 $ 47,099 Noncurrent Liabilities 170,511 194,162 Equity 1,337 1,337 Total Liabilities and Equity $ 219,387 $ 242,598 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $87 million and $97 million , respectively.
Public Service Co Of Oklahoma [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741
Public Service Co Of Oklahoma [Member] | Carrying Amount in AEPSC's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772
Southwestern Electric Power Co [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Significant Variable Interest	Three Months Ended June 30, Six Months Ended June 30, Company 2015 2014 2015 2014 (in thousands) APCo $ 52,722 $ 53,959 $ 100,970 $ 104,096 I&M 31,134 30,103 64,636 62,073 OPCo 40,907 40,441 80,137 79,490 PSO 24,442 22,889 47,966 47,329 SWEPCo 31,900 32,718 63,414 65,741
Southwestern Electric Power Co [Member] | Carrying Amount in AEPSC's Accounts Payable [Member]
Carrying Amount and Classification of Variable Interest in Accounts Payable	June 30, 2015 December 31, 2014 Company As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) APCo $ 19,141 $ 19,141 $ 30,692 $ 30,692 I&M 11,173 11,173 22,480 22,480 OPCo 15,423 15,423 24,695 24,695 PSO 9,017 9,017 15,338 15,338 SWEPCo 12,114 12,114 20,772 20,772
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 June 30, 2015 and December 31, 2014 (in thousands) Sabine ASSETS 2015 2014 Current Assets $ 57,592 $ 67,981 Net Property, Plant and Equipment 142,265 145,491 Other Noncurrent Assets 59,717 51,578 Total Assets $ 259,574 $ 265,050 LIABILITIES AND EQUITY Current Liabilities $ 28,122 $ 36,286 Noncurrent Liabilities 231,155 228,349 Equity 297 415 Total Liabilities and Equity $ 259,574 $ 265,050
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Companys Investment In Joint Venture	June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in thousands) Capital Contribution from SWEPCo $ 7,643 $ 7,643 $ 7,643 $ 7,643 Retained Earnings 5,540 5,540 3,819 3,819 SWEPCo's Guarantee of Debt — 106,408 (a) — 104,334 (a) Total Investment in DHLC $ 13,183 $ 119,591 $ 11,462 $ 115,796 (a) Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $56 million and $56 million in 2015 and 2014 , respectively.
PATH West Virginia Transmission Co, LLC [Member]
Companys Investment In Joint Venture	June 30, 2015 December 31, 2014 As Reported on the Balance Sheet Maximum Exposure As Reported on the Balance Sheet Maximum Exposure (in millions) Capital Contribution from AEP $ 19 $ 19 $ 19 $ 19 Retained Earnings 2 2 2 2 Total Investment in PATH-WV $ 21 $ 21 $ 21 $ 21
Appalachian Consumer Rate Relief Funding [Member] | Appalachian Power Co [Member]
Consolidated Assets and Liabilities of Variable Interest Entities	APPALACHIAN POWER COMPANY AND SUBSIDIARIES VARIABLE INTEREST ENTITIES June 30, 2015 and December 31, 2014 (in thousands) Appalachian Consumer Rate Relief Funding ASSETS 2015 2014 Current Assets $ 19,145 $ 18,099 Other Noncurrent Assets (a) 346,809 358,264 Total Assets $ 365,954 $ 376,363 LIABILITIES AND EQUITY Current Liabilities $ 26,912 $ 26,809 Noncurrent Liabilities 337,316 347,652 Equity 1,726 1,902 Total Liabilities and Equity $ 365,954 $ 376,363 (a) Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $4 million and $4 million , respectively.

Disposition Plant Severance (Ta

Disposition Plant Severance (Tables)	6 Months Ended
	Jun. 30, 2015
Disposition Plant Severance [Member]
Remaining Accrual	Disposition Plant Severance Activity (in millions) Balance as of December 31, 2014 $ 29 Incurred 3 Settled (11 ) Adjustments — Balance as of June 30, 2015 $ 21
Appalachian Power Co [Member]
Total Cost Incurred	Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289
Remaining Accrual	Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant.
Indiana Michigan Power Co [Member]
Total Cost Incurred	Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289
Remaining Accrual	Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant.
Ohio Power Co [Member]
Total Cost Incurred	Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289
Remaining Accrual	Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant.
Public Service Co Of Oklahoma [Member]
Total Cost Incurred	Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289
Remaining Accrual	Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant.
Southwestern Electric Power Co [Member]
Total Cost Incurred	Company Total Cost Incurred (in thousands) APCo $ 7,112 I&M 8,185 OPCo 80 PSO 288 SWEPCo 289
Remaining Accrual	Balance as of Expense Allocation from Incurred by Registrant Remaining Balance as of Company December 31, 2014 AEPSC Subsidiaries Settled Adjustments June 30, 2015 (in thousands) APCo $ 9,304 $ (5 ) $ 817 $ (4,478 ) (a) $ (129 ) $ 5,509 I&M 8,023 (3 ) 363 (3,459 ) — 4,924 PSO 134 (3 ) 416 (116 ) — 431 SWEPCo 84 (4 ) — (79 ) — 1 (a) Settled includes amounts received from affiliates for expenses related to joint plant.

Property, Plant and Equipment40

Property, Plant and Equipment Property, Plant and Equipment (Tables)	6 Months Ended
	Jun. 30, 2015
Asset Retirement Obligation (ARO)	Carrying Amount of ARO (in millions) ARO as of December 31, 2014 $ 2,019 Accretion Expense 50 Liabilities Incurred 47 Liabilities Settled (22 ) Revisions in Cash Flow Estimates 48 ARO as of June 30, 2015 $ 2,142
Appalachian Power Co [Member]
Asset Retirement Obligation (ARO)	ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.
Indiana Michigan Power Co [Member]
Asset Retirement Obligation (ARO)	ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.
Ohio Power Co [Member]
Asset Retirement Obligation (ARO)	ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.
Public Service Co Of Oklahoma [Member]
Asset Retirement Obligation (ARO)	ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.
Southwestern Electric Power Co [Member]
Asset Retirement Obligation (ARO)	ARO as of Revisions in December 31, Accretion Liabilities Liabilities Cash Flow ARO as of Company 2014 Expense Incurred Settled Estimates June 30, 2015 (in thousands) APCo (a)(d) $ 148,377 $ 4,122 $ — $ (10,503 ) $ 13,962 $ 155,958 I&M (a)(b)(d) 1,342,549 31,731 — (1,222 ) 5,639 1,378,697 OPCo (d)(e) 1,361 41 — (8 ) — 1,394 PSO (a)(d) 38,020 1,214 5,336 (115 ) 1,916 46,371 SWEPCo (a)(c)(d) 94,394 2,725 12,191 (2,189 ) 6,348 113,469 (a) Includes ARO related to ash disposal facilities. (b) Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014. (c) Includes ARO related to Sabine and DHLC. (d) Includes ARO related to asbestos removal. (e) Not impacted by the CCR rule.

Significant Accounting Matter41

Significant Accounting Matters (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Basic and Diluted EPS Calculations
Earnings Attributable to AEP Common Shareholders	$ 430,000	$ 390,000	$ 1,059,000	$ 950,000
Total Basic Earnings Per Share Attributable to AEP Common Shareholders	$ 0.88	$ 0.80	$ 2.16	$ 1.95
Weighted Average Dilutive Effect of:
Total Diluted Earnings Per Share Attributable to AEP Common Shareholders	$ 0.88	$ 0.80	$ 2.16	$ 1.95
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	$ 58,470	$ 31,697	$ 104,174	$ 53,557
Restricted Stock Units [Member]
Weighted Average Dilutive Effect of:
Weighted Average Dilutive Effect of Shares	300,000	200,000	300,000	300,000
Dilutive Securities, Effect on Basic Earnings Per Share	$ 0	$ 0	$ 0	$ 0

Comprehensive Income (Details)

Comprehensive Income (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		$ (103,000)	$ (109,000)	$ (103,000)	$ (115,000)
Change in Fair Value Recognized in AOCI		(2,000)	4,000	2,000	(10,000)
Amounts Reclassified from AOCI		3,000	1,000	(6,000)	21,000
Net Current Period Other Comprehensive Income		1,000	5,000	(4,000)	11,000
Pension and OPEB Adjustment Related to Mitchell Plant				5,000
Ending Balance in AOCI		(102,000)	(104,000)	(102,000)	(104,000)
Commodity:
Generation & Marketing Revenues		147,000	171,000	303,000	288,000
Purchased Electricity for Resale		601,000	473,000	1,319,000	1,111,000
Other Operation Expense		695,000	760,000	1,441,000	1,540,000
Maintenance Expense		333,000	340,000	627,000	632,000
Interest Rate and Foreign Currency:
Depreciation and Amortization Expense		506,000	443,000	1,011,000	934,000
Interest Expense		224,000	221,000	447,000	441,000
Income Tax (Expense) Credit		(225,000)	(215,000)	(558,000)	(522,000)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		3,000	1,000	(6,000)	21,000
Gains and Losses on Available-for-Sale Securities
Interest Expense		224,000	221,000	447,000	441,000
Income Tax (Expense) Credit		(225,000)	(215,000)	(558,000)	(522,000)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		3,000	1,000	(6,000)	21,000
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(225,000)	(215,000)	(558,000)	(522,000)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		3,000	1,000	(6,000)	21,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		3,000	1,000	(6,000)	21,000
Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI		2,000	0	(7,000)	19,000
Commodity:
Subtotal - Commodity		3,000	0	(10,000)	30,000
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		3,000	0	(10,000)	30,000
Reclassifications from AOCI, before Income Tax (Expense) Credit		3,000	0	(10,000)	30,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2,000	0	(7,000)	19,000
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		3,000	0	(10,000)	30,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2,000	0	(7,000)	19,000
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		3,000	0	(10,000)	30,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2,000	0	(7,000)	19,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2,000	0	(7,000)	19,000
Securities Available for Sale [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		9,000	7,000	8,000	7,000
Change in Fair Value Recognized in AOCI		(1,000)	1,000	0	1,000
Amounts Reclassified from AOCI		0	0	0	0
Net Current Period Other Comprehensive Income		(1,000)	1,000	0	1,000
Pension and OPEB Adjustment Related to Mitchell Plant				0
Ending Balance in AOCI		8,000	8,000	8,000	8,000
Interest Rate and Foreign Currency:
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	0
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	0
Amortization of Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	0
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	0
Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(88,000)	(98,000)	(93,000)	(99,000)
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		1,000	1,000	1,000	2,000
Net Current Period Other Comprehensive Income		1,000	1,000	1,000	2,000
Pension and OPEB Adjustment Related to Mitchell Plant				5,000
Ending Balance in AOCI		(87,000)	(97,000)	(87,000)	(97,000)
Commodity:
Subtotal - Commodity		1,000	2,000	1,000	4,000
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		1,000	2,000	1,000	4,000
Reclassifications from AOCI, before Income Tax (Expense) Credit		1,000	2,000	1,000	4,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1,000	1,000	1,000	2,000
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		1,000	2,000	1,000	4,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1,000	1,000	1,000	2,000
Amortization of Pension and OPEB
Prior Service Cost (Credit)		(5,000)	(5,000)	(10,000)	(10,000)
Actuarial (Gains)/Losses		6,000	7,000	11,000	14,000
Reclassifications from AOCI, before Income Tax (Expense) Credit		1,000	2,000	1,000	4,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1,000	1,000	1,000	2,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		1,000	1,000	1,000	2,000
Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(6,000)	4,000	1,000	0
Change in Fair Value Recognized in AOCI		(1,000)	3,000	2,000	(11,000)
Amounts Reclassified from AOCI		2,000	(1,000)	(8,000)	17,000
Net Current Period Other Comprehensive Income		1,000	2,000	(6,000)	6,000
Pension and OPEB Adjustment Related to Mitchell Plant				0
Ending Balance in AOCI		(5,000)	6,000	(5,000)	6,000
Commodity:
Subtotal - Commodity		3,000	(2,000)	(11,000)	26,000
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		3,000	(2,000)	(11,000)	26,000
Reclassifications from AOCI, before Income Tax (Expense) Credit		3,000	(2,000)	(11,000)	26,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2,000	(1,000)	(8,000)	17,000
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		3,000	(2,000)	(11,000)	26,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2,000	(1,000)	(8,000)	17,000
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		3,000	(2,000)	(11,000)	26,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2,000	(1,000)	(8,000)	17,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2,000	(1,000)	(8,000)	17,000
Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(18,000)	(22,000)	(19,000)	(23,000)
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		0	1,000	1,000	2,000
Net Current Period Other Comprehensive Income		0	1,000	1,000	2,000
Pension and OPEB Adjustment Related to Mitchell Plant				0
Ending Balance in AOCI		(18,000)	(21,000)	(18,000)	(21,000)
Commodity:
Subtotal - Commodity		0	2,000	1,000	4,000
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		0	2,000	1,000	4,000
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	2,000	1,000	4,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	1,000	1,000	2,000
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	2,000	1,000	4,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	1,000	1,000	2,000
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	2,000	1,000	4,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	1,000	1,000	2,000
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	1,000	1,000	2,000
Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		1,000	0	(3,000)	11,000
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		1,000	0	(3,000)	11,000
Amortization of Pension and OPEB
Income Tax (Expense) Credit		1,000	0	(3,000)	11,000
Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		0	1,000	0	2,000
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		0	1,000	0	2,000
Amortization of Pension and OPEB
Income Tax (Expense) Credit		0	1,000	0	2,000
Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity:
Generation & Marketing Revenues		(4,000)	0	(17,000)	0
Purchased Electricity for Resale		7,000	(2,000)	6,000	29,000
Regulatory Assets/(Liabilities), Net	[1]			0	(3,000)
Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Interest Expense		0	2,000	1,000	4,000
Gains and Losses on Available-for-Sale Securities
Interest Expense		0	2,000	1,000	4,000
Appalachian Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		4,703	2,864	5,032	2,951
Change in Fair Value Recognized in AOCI		0	103	0	1,686
Amounts Reclassified from AOCI		(456)	(270)	(785)	(1,940)
Net Current Period Other Comprehensive Income		(456)	(167)	(785)	(254)
Ending Balance in AOCI		4,247	2,697	4,247	2,697
Commodity:
Generation & Marketing Revenues		2,692	2,547	5,013	4,567
Purchased Electricity for Resale		65,715	86,033	178,384	255,024
Other Operation Expense		103,720	99,896	209,790	193,434
Maintenance Expense		57,037	69,484	109,334	129,574
Interest Rate and Foreign Currency:
Depreciation and Amortization Expense		96,297	95,650	196,440	200,236
Interest Expense		48,684	53,130	98,975	104,802
Income Tax (Expense) Credit		(42,713)	(23,577)	(127,861)	(89,825)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(456)	(270)	(785)	(1,940)
Gains and Losses on Available-for-Sale Securities
Interest Expense		48,684	53,130	98,975	104,802
Income Tax (Expense) Credit		(42,713)	(23,577)	(127,861)	(89,825)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(456)	(270)	(785)	(1,940)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(42,713)	(23,577)	(127,861)	(89,825)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(456)	(270)	(785)	(1,940)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(456)	(270)	(785)	(1,940)
Appalachian Power Co [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI		2	63	131	(1,274)
Commodity:
Subtotal - Commodity		3	98	202	(1,958)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		3	98	202	(1,958)
Reclassifications from AOCI, before Income Tax (Expense) Credit		3	98	202	(1,958)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2	63	131	(1,274)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		3	98	202	(1,958)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2	63	131	(1,274)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		3	98	202	(1,958)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2	63	131	(1,274)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2	63	131	(1,274)
Appalachian Power Co [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		678	(566)	1,136	(233)
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		(458)	(333)	(916)	(666)
Net Current Period Other Comprehensive Income		(458)	(333)	(916)	(666)
Ending Balance in AOCI		220	(899)	220	(899)
Commodity:
Subtotal - Commodity		(705)	(513)	(1,409)	(1,025)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		(705)	(513)	(1,409)	(1,025)
Reclassifications from AOCI, before Income Tax (Expense) Credit		(705)	(513)	(1,409)	(1,025)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(458)	(333)	(916)	(666)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		(705)	(513)	(1,409)	(1,025)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(458)	(333)	(916)	(666)
Amortization of Pension and OPEB
Prior Service Cost (Credit)		(1,283)	(1,283)	(2,565)	(2,565)
Actuarial (Gains)/Losses		578	770	1,156	1,540
Reclassifications from AOCI, before Income Tax (Expense) Credit		(705)	(513)	(1,409)	(1,025)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(458)	(333)	(916)	(666)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(458)	(333)	(916)	(666)
Appalachian Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	87	0	94
Change in Fair Value Recognized in AOCI		0	103	0	1,686
Amounts Reclassified from AOCI		0	(190)	0	(1,780)
Net Current Period Other Comprehensive Income		0	(87)	0	(94)
Ending Balance in AOCI		0	0	0	0
Commodity:
Subtotal - Commodity		0	(292)	0	(2,738)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		0	(292)	0	(2,738)
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	(292)	0	(2,738)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	(190)	0	(1,780)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	(292)	0	(2,738)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	(190)	0	(1,780)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	(292)	0	(2,738)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	(190)	0	(1,780)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	(190)	0	(1,780)
Appalachian Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		4,025	3,343	3,896	3,090
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		2	253	131	506
Net Current Period Other Comprehensive Income		2	253	131	506
Ending Balance in AOCI		4,027	3,596	4,027	3,596
Commodity:
Subtotal - Commodity		3	390	202	780
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		3	390	202	780
Reclassifications from AOCI, before Income Tax (Expense) Credit		3	390	202	780
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2	253	131	506
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		3	390	202	780
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2	253	131	506
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		3	390	202	780
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2	253	131	506
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		2	253	131	506
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		1	35	71	(684)
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		1	35	71	(684)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		1	35	71	(684)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		(247)	(180)	(493)	(359)
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		(247)	(180)	(493)	(359)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(247)	(180)	(493)	(359)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity:
Purchased Electricity for Resale		0	(64)	0	(526)
Other Operation Expense				0	(10)
Maintenance Expense				0	(20)
Property, Plant and Equipment				0	(17)
Regulatory Assets/(Liabilities), Net	[1]	0	(228)	0	(2,165)
Appalachian Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Interest Expense		3	390	202	780
Gains and Losses on Available-for-Sale Securities
Interest Expense		3	390	202	780
Indiana Michigan Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(14,081)	(15,041)	(14,360)	(15,509)
Change in Fair Value Recognized in AOCI		0	68	0	1,130
Amounts Reclassified from AOCI		278	325	557	(269)
Net Current Period Other Comprehensive Income		278	393	557	861
Ending Balance in AOCI		(13,803)	(14,648)	(13,803)	(14,648)
Commodity:
Generation & Marketing Revenues		812	549	1,840	549
Purchased Electricity for Resale		50,260	27,086	106,167	32,448
Other Operation Expense		137,306	146,272	266,266	287,622
Maintenance Expense		59,829	54,246	107,180	102,811
Interest Rate and Foreign Currency:
Depreciation and Amortization Expense		49,540	49,446	100,947	99,477
Interest Expense		22,968	23,705	45,745	49,338
Income Tax (Expense) Credit		(24,264)	(12,627)	(59,034)	(50,942)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		278	325	557	(269)
Gains and Losses on Available-for-Sale Securities
Interest Expense		22,968	23,705	45,745	49,338
Income Tax (Expense) Credit		(24,264)	(12,627)	(59,034)	(50,942)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		278	325	557	(269)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(24,264)	(12,627)	(59,034)	(50,942)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		278	325	557	(269)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		278	325	557	(269)
Indiana Michigan Power Co [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI		268	282	535	(355)
Commodity:
Subtotal - Commodity		411	433	822	(547)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		411	433	822	(547)
Reclassifications from AOCI, before Income Tax (Expense) Credit		411	433	822	(547)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		268	282	535	(355)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		411	433	822	(547)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		268	282	535	(355)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		411	433	822	(547)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		268	282	535	(355)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		268	282	535	(355)
Indiana Michigan Power Co [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		58	464	46	421
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		10	43	22	86
Net Current Period Other Comprehensive Income		10	43	22	86
Ending Balance in AOCI		68	507	68	507
Commodity:
Subtotal - Commodity		16	64	34	130
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		16	64	34	130
Reclassifications from AOCI, before Income Tax (Expense) Credit		16	64	34	130
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		10	43	22	86
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		16	64	34	130
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		10	43	22	86
Amortization of Pension and OPEB
Prior Service Cost (Credit)		(199)	(198)	(398)	(397)
Actuarial (Gains)/Losses		215	262	432	527
Reclassifications from AOCI, before Income Tax (Expense) Credit		16	64	34	130
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		10	43	22	86
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		10	43	22	86
Indiana Michigan Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	61	0	46
Change in Fair Value Recognized in AOCI		0	68	0	1,130
Amounts Reclassified from AOCI		0	(129)	0	(1,176)
Net Current Period Other Comprehensive Income		0	(61)	0	(46)
Ending Balance in AOCI		0	0	0	0
Commodity:
Subtotal - Commodity		0	(198)	0	(1,809)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		0	(198)	0	(1,809)
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	(198)	0	(1,809)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	(129)	0	(1,176)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	(198)	0	(1,809)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	(129)	0	(1,176)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	(198)	0	(1,809)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	(129)	0	(1,176)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	(129)	0	(1,176)
Indiana Michigan Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(14,139)	(15,566)	(14,406)	(15,976)
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		268	411	535	821
Net Current Period Other Comprehensive Income		268	411	535	821
Ending Balance in AOCI		(13,871)	(15,155)	(13,871)	(15,155)
Commodity:
Subtotal - Commodity		411	631	822	1,262
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		411	631	822	1,262
Reclassifications from AOCI, before Income Tax (Expense) Credit		411	631	822	1,262
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		268	411	535	821
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		411	631	822	1,262
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		268	411	535	821
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		411	631	822	1,262
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		268	411	535	821
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		268	411	535	821
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		143	151	287	(192)
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		143	151	287	(192)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		143	151	287	(192)
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI		10	43
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		6	21	12	44
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		10	43
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		6	21	12	44
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		10	43
Amortization of Pension and OPEB
Income Tax (Expense) Credit		6	21	12	44
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		10	43
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		10	43
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Ending Balance in AOCI		0	0	0	0
Commodity:
Purchased Electricity for Resale		0	(95)	0	(812)
Other Operation Expense				0	(7)
Maintenance Expense				0	(7)
Property, Plant and Equipment				0	(10)
Regulatory Assets/(Liabilities), Net	[1]	0	(103)	0	(973)
Indiana Michigan Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Interest Expense		411	631	822	1,262
Gains and Losses on Available-for-Sale Securities
Interest Expense		411	631	822	1,262
Ohio Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		5,259	6,631	5,602	7,079
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		(343)	(343)	(686)	(791)
Net Current Period Other Comprehensive Income		(343)	(343)	(686)	(791)
Ending Balance in AOCI		4,916	6,288	4,916	6,288
Commodity:
Generation & Marketing Revenues		2,346	1,756	4,463	3,064
Purchased Electricity for Resale		116,434	64,059	258,514	143,189
Other Operation Expense		129,829	131,485	276,673	282,911
Maintenance Expense		34,214	48,590	81,787	83,241
Interest Rate and Foreign Currency:
Depreciation and Amortization Expense		55,640	51,485	114,852	110,184
Interest Expense		31,271	32,759	63,720	65,766
Income Tax (Expense) Credit		(26,213)	(35,842)	(62,100)	(69,894)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(791)
Gains and Losses on Available-for-Sale Securities
Interest Expense		31,271	32,759	63,720	65,766
Income Tax (Expense) Credit		(26,213)	(35,842)	(62,100)	(69,894)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(791)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(26,213)	(35,842)	(62,100)	(69,894)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(791)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(791)
Ohio Power Co [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI		(343)	(343)	(686)	(791)
Commodity:
Subtotal - Commodity		(527)	(527)	(1,054)	(1,216)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		(527)	(527)	(1,054)	(1,216)
Reclassifications from AOCI, before Income Tax (Expense) Credit		(527)	(527)	(1,054)	(1,216)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(791)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		(527)	(527)	(1,054)	(1,216)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(791)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(527)	(527)	(1,054)	(1,216)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(791)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(791)
Ohio Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	0	0	105
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		0	0	0	(105)
Net Current Period Other Comprehensive Income		0	0	0	(105)
Ending Balance in AOCI		0	0	0	0
Commodity:
Subtotal - Commodity		0	0	0	(162)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		0	0	0	(162)
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(162)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(105)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(162)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(105)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(162)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(105)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(105)
Ohio Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		5,259	6,631	5,602	6,974
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		(343)	(343)	(686)	(686)
Net Current Period Other Comprehensive Income		(343)	(343)	(686)	(686)
Ending Balance in AOCI		4,916	6,288	4,916	6,288
Commodity:
Subtotal - Commodity		(527)	(527)	(1,054)	(1,054)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		(527)	(527)	(1,054)	(1,054)
Reclassifications from AOCI, before Income Tax (Expense) Credit		(527)	(527)	(1,054)	(1,054)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(686)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		(527)	(527)	(1,054)	(1,054)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(686)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(527)	(527)	(1,054)	(1,054)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(686)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(343)	(343)	(686)	(686)
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		(184)	(184)	(368)	(425)
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		(184)	(184)	(368)	(425)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(184)	(184)	(368)	(425)
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity:
Other Operation Expense		0	0	0	(11)
Maintenance Expense		0	0	0	(11)
Property, Plant and Equipment		0	0	0	(18)
Regulatory Assets/(Liabilities), Net	[1]	0	0	0	(122)
Ohio Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Depreciation and Amortization Expense		(3)	(3)	(6)	(6)
Interest Expense		(524)	(524)	(1,048)	(1,048)
Gains and Losses on Available-for-Sale Securities
Interest Expense		(524)	(524)	(1,048)	(1,048)
Public Service Co Of Oklahoma [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		4,753	5,512	4,943	5,758
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		(190)	(190)	(380)	(436)
Net Current Period Other Comprehensive Income		(190)	(190)	(380)	(436)
Ending Balance in AOCI		4,563	5,322	4,563	5,322
Commodity:
Generation & Marketing Revenues		729	1,437	1,549	1,515
Purchased Electricity for Resale		85,036	104,604	150,559	184,295
Other Operation Expense		61,028	62,785	121,793	121,496
Maintenance Expense		25,943	29,678	47,083	54,423
Interest Rate and Foreign Currency:
Depreciation and Amortization Expense		29,782	24,607	59,316	48,589
Interest Expense		14,852	13,779	29,422	27,096
Income Tax (Expense) Credit		(15,921)	(13,244)	(23,962)	(18,233)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(190)	(190)	(380)	(436)
Gains and Losses on Available-for-Sale Securities
Interest Expense		14,852	13,779	29,422	27,096
Income Tax (Expense) Credit		(15,921)	(13,244)	(23,962)	(18,233)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(190)	(190)	(380)	(436)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(15,921)	(13,244)	(23,962)	(18,233)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(190)	(190)	(380)	(436)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(190)	(190)	(380)	(436)
Public Service Co Of Oklahoma [Member] | Cash Flow Hedges [Member]
Commodity:
Subtotal - Commodity		(292)	(292)	(584)	(672)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		(292)	(292)	(584)	(672)
Reclassifications from AOCI, before Income Tax (Expense) Credit		(292)	(292)	(584)	(672)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		(292)	(292)	(584)	(672)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(292)	(292)	(584)	(672)
Public Service Co Of Oklahoma [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	0	0	57
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		0	0	0	(57)
Net Current Period Other Comprehensive Income		0	0	0	(57)
Ending Balance in AOCI		0	0	0	0
Commodity:
Subtotal - Commodity		0	0	0	(88)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		0	0	0	(88)
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(88)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(57)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(88)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(57)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(88)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(57)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(57)
Public Service Co Of Oklahoma [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		4,753	5,512	4,943	5,701
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		(190)	(190)	(380)	(379)
Net Current Period Other Comprehensive Income		(190)	(190)	(380)	(379)
Ending Balance in AOCI		4,563	5,322	4,563	5,322
Commodity:
Subtotal - Commodity		(292)	(292)	(584)	(584)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		(292)	(292)	(584)	(584)
Reclassifications from AOCI, before Income Tax (Expense) Credit		(292)	(292)	(584)	(584)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(190)	(190)	(380)	(379)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		(292)	(292)	(584)	(584)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(190)	(190)	(380)	(379)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		(292)	(292)	(584)	(584)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(190)	(190)	(380)	(379)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(190)	(190)	(380)	(379)
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI				(380)	(436)
Interest Rate and Foreign Currency:
Reclassifications from AOCI, Net of Income Tax (Expense) Credit				(380)	(436)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, Net of Income Tax (Expense) Credit				(380)	(436)
Amortization of Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit				(380)	(436)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit				(380)	(436)
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		(102)	(102)	(204)	(236)
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		(102)	(102)	(204)	(236)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(102)	(102)	(204)	(236)
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity:
Other Operation Expense		0	0	0	(8)
Maintenance Expense		0	0	0	(9)
Property, Plant and Equipment		0	0	0	(13)
Regulatory Assets/(Liabilities), Net	[1]	0	0	0	(58)
Public Service Co Of Oklahoma [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Interest Expense		(292)	(292)	(584)	(584)
Gains and Losses on Available-for-Sale Securities
Interest Expense		(292)	(292)	(584)	(584)
Southwestern Electric Power Co [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(7,139)	(8,176)	(7,466)	(8,444)
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		328	332	655	600
Net Current Period Other Comprehensive Income		328	332	655	600
Ending Balance in AOCI		(6,811)	(7,844)	(6,811)	(7,844)
Commodity:
Generation & Marketing Revenues		364	684	868	1,049
Purchased Electricity for Resale		27,188	40,255	47,202	101,420
Other Operation Expense		67,899	69,304	133,444	137,841
Maintenance Expense		38,237	33,668	65,651	64,079
Interest Rate and Foreign Currency:
Depreciation and Amortization Expense		47,964	45,864	94,918	91,525
Interest Expense		31,945	31,738	62,160	63,614
Income Tax (Expense) Credit		(26,887)	(17,045)	(48,059)	(29,210)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		328	332	655	600
Gains and Losses on Available-for-Sale Securities
Interest Expense		31,945	31,738	62,160	63,614
Income Tax (Expense) Credit		(26,887)	(17,045)	(48,059)	(29,210)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		328	332	655	600
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(26,887)	(17,045)	(48,059)	(29,210)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		328	332	655	600
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		328	332	655	600
Southwestern Electric Power Co [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI		567	567	1,134	1,069
Commodity:
Subtotal - Commodity		872	872	1,744	1,643
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		872	872	1,744	1,643
Reclassifications from AOCI, before Income Tax (Expense) Credit		872	872	1,744	1,643
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		567	567	1,134	1,069
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		872	872	1,744	1,643
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		567	567	1,134	1,069
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		872	872	1,744	1,643
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		567	567	1,134	1,069
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		567	567	1,134	1,069
Southwestern Electric Power Co [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		3,330	4,560	3,570	4,794
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		(239)	(235)	(479)	(469)
Net Current Period Other Comprehensive Income		(239)	(235)	(479)	(469)
Ending Balance in AOCI		3,091	4,325	3,091	4,325
Commodity:
Subtotal - Commodity		(368)	(362)	(737)	(722)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		(368)	(362)	(737)	(722)
Reclassifications from AOCI, before Income Tax (Expense) Credit		(368)	(362)	(737)	(722)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(239)	(235)	(479)	(469)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		(368)	(362)	(737)	(722)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(239)	(235)	(479)	(469)
Amortization of Pension and OPEB
Prior Service Cost (Credit)		(467)	(477)	(934)	(955)
Actuarial (Gains)/Losses		99	115	197	233
Reclassifications from AOCI, before Income Tax (Expense) Credit		(368)	(362)	(737)	(722)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(239)	(235)	(479)	(469)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(239)	(235)	(479)	(469)
Southwestern Electric Power Co [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		0	0	0	66
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		0	0	0	(66)
Net Current Period Other Comprehensive Income		0	0	0	(66)
Ending Balance in AOCI		0	0	0	0
Commodity:
Subtotal - Commodity		0	0	0	(101)
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		0	0	0	(101)
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(101)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(66)
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(101)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(66)
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		0	0	0	(101)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(66)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		0	0	0	(66)
Southwestern Electric Power Co [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Beginning Balance in AOCI		(10,469)	(12,736)	(11,036)	(13,304)
Change in Fair Value Recognized in AOCI		0	0	0	0
Amounts Reclassified from AOCI		567	567	1,134	1,135
Net Current Period Other Comprehensive Income		567	567	1,134	1,135
Ending Balance in AOCI		(9,902)	(12,169)	(9,902)	(12,169)
Commodity:
Subtotal - Commodity		872	872	1,744	1,744
Interest Rate and Foreign Currency:
Subtotal - Interest Rate and Foreign Currency		872	872	1,744	1,744
Reclassifications from AOCI, before Income Tax (Expense) Credit		872	872	1,744	1,744
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		567	567	1,134	1,135
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, before Income Tax (Expense) Credit		872	872	1,744	1,744
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		567	567	1,134	1,135
Amortization of Pension and OPEB
Reclassifications from AOCI, before Income Tax (Expense) Credit		872	872	1,744	1,744
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		567	567	1,134	1,135
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		567	567	1,134	1,135
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI		328
Interest Rate and Foreign Currency:
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		328
Gains and Losses on Available-for-Sale Securities
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		328
Amortization of Pension and OPEB
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		328
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		328
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		305	305	610	574
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		305	305	610	574
Amortization of Pension and OPEB
Income Tax (Expense) Credit		305	305	610	574
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Pension and OPEB [Member]
Accumulated Other Comprehensive Income (Loss), Net of Tax [Roll Forward]
Amounts Reclassified from AOCI		(239)	(235)
Interest Rate and Foreign Currency:
Income Tax (Expense) Credit		(129)	(127)	(258)	(253)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(239)	(235)
Gains and Losses on Available-for-Sale Securities
Income Tax (Expense) Credit		(129)	(127)	(258)	(253)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(239)	(235)
Amortization of Pension and OPEB
Income Tax (Expense) Credit		(129)	(127)	(258)	(253)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(239)	(235)
Reclassifications from AOCI, Net of Income Tax (Expense) Credit		(239)	(235)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Commodity [Member] | Cash Flow Hedges [Member]
Commodity:
Other Operation Expense		0	0	0	(13)
Maintenance Expense		0	0	0	(10)
Property, Plant and Equipment		0	0	0	(11)
Regulatory Assets/(Liabilities), Net	[1]	0	0	0	(67)
Southwestern Electric Power Co [Member] | Reclassifications from Accumulated Other Comprehensive Income [Member] | Interest Rate and Foreign Currency [Member] | Cash Flow Hedges [Member]
Interest Rate and Foreign Currency:
Interest Expense		872	872	1,744	1,744
Gains and Losses on Available-for-Sale Securities
Interest Expense		$ 872	$ 872	$ 1,744	$ 1,744
[1]	Represents realized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.

Rate Matters - Regulatory Asset

Rate Matters - Regulatory Assets (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 5,021,000	$ 4,264,000
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,038,924	857,872
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	839,110	536,152
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,237,933	1,318,939
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	170,834	154,327
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	417,551	393,602
Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	137,000	226,000
Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	44,886	125,748
Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	54,992	13,649
Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	10,527	10,483
Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	17,693
Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	4,900	12,115
Amos Plant Transfer Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,950	1,377
Asset Retirement Obligation [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,320	1,144
Asset Retirement Obligation Costs Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	51,000	0
Asset Retirement Obligation Costs Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	24,399	0
Asset Retirement Obligation Costs Related to Retired Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	27,079	0
Carbon Capture and Storage Commercial Scale Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	1,287
Carbon Capture and Storage Product Validation Facility [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	13,000
Carbon Capture and Storage Product Validation Facility - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	13,264
Cook Plant Turbine [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	8,169	6,596
Deferred Cook Plant Life Cycle Management Project Costs - Michigan [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	2,721	1,222
Demand Response Program Costs - Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	11,000	9,000
Demand Response Program Costs - Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	10,781	8,791
Expanded Net Energy Charge - Coal Inventory [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	3,421
Expanded Net Energy Charge - Construction Surcharge [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	2,307
IGCC Pre-Construction Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	11,000
IGCC Pre-Constructions Costs - West Virginia, FERC [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	10,838
Materials and Supplies Related to Retired Plants [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	19,000	0
Materials and Supplies Related to Retired Plants [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	7,588	0
Materials and Supplies Related to Retired Plants [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	11,722	0
Ormet Delayed Payment Arrangement [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	10,000	10,000
Ormet Delayed Payment Arrangement [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	10,483	10,483
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	23,000	43,000
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	168	168
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	547	860
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	44	0
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	1,079
Other Regulatory Assets Pending Final Regulatory Approval [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	558	558
Rate Case Expenses [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	8,126
Shipe Road Transmission Project [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	3,022	2,287
Storm Related Costs [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	20,000	20,000
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	3,000	100,000
Storm Related Costs [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	16,614
Storm Related Costs - Indiana [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	857	1,074
Storm Related Costs - West Virginia [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	65,206
Stranded Costs on Abandoned Plants [Member] | Regulatory Assets Currently Not Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	3,897	3,897
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	0	20,000
Vegetation Management Program - West Virginia [Member] | Regulatory Assets Currently Earning Return [Member] | Regulatory Assets Pending Final Regulatory Approval [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 0	$ 19,089

Rate Matters - East Companies (

Rate Matters - East Companies (Details) - Subsequent Event Type [Domain] $ in Thousands	6 Months Ended
	Jun. 30, 2015USD ($)$ / MWD$ / MWh	Dec. 31, 2014USD ($)
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 5,021,000	$ 4,264,000
Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	1,038,924	857,872
Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	839,110	536,152
Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Regulatory Assets, Noncurrent	$ 1,237,933	$ 1,318,939
Kentucky 2014 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Requested Return on Equity	10.62%
Requested Net Increase in Rates	$ 70,000
Requested Increase in Rider Rates	75,000
Requested Decrease in Annual Base Rates	5,000
Recommended Net Increase in Rates as Proposed in Stipulation Agreement	45,000
Recommended Increase in Rider Rates as Proposed in Stipulation Agreement	68,000
Recommended Decrease in Annual Base Rates as Proposed in Stipulation Agreement	23,000
Amount of Storm Costs Recommended for Recovery as Proposed in Stipulation Agreement	12,000
Amount of Off-System Sales Margins Included in the Annual Base Rates as Proposed in Stipulation Agreement	$ 15,000
Percentage of Off-System Sales Margins Above the Amount in Base Rates to be Shared with Customers as Proposed in Stipulation Agreement	75.00%
Percentage of Off-System Sales Margins Above the Amount in Base Rates to be Retained by KPCo as Proposed in Stipulation Agreement	25.00%
Approved Net Revenue Increase	$ 45,000
Amount of IGCC and Carbon Capture Costs Approved for Recovery	$ 2,000
Recovery Period of Approved IGCC and Carbon Capture Costs	25 years
Kentucky Fuel Adjustment Clause Review [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Regulatory Disallowance Resulting from a Commission Order	$ 36,000
Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
PUCO-ordered Fixed Price per MW Day for Customers Who Switch During ESP Period | $ / MWD	188.88
Reliability Pricing Model Rate per MW Day in Effect through May 2014 | $ / MWD	34
Reliability Pricing Model Rate per MW Day in Effect from June 2014 through May 2015 | $ / MWD	150
Retail Stability Rider through May 2014 ($ Per MWh) | $ / MWh	3.50
Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh) | $ / MWh	4
Amount of Retail Stability Rider Applied to the Deferred Capacity Costs ($ per MWh) | $ / MWh	1
Intended Retail Stability Rider Rate to be Continued Until Capacity Deferral Balance is Collected ($ per MWh) | $ / MWh	4
Retail Stability Rider Rate to be Continued Until Capacity Deferral Balance is Collected as Ordered by the PUCO ($ per MWh) | $ / MWh	4
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months)	32 months
Percentage of Standard Service Offer Load Which Registrant Conducted Energy Only Auctions for Delivery from April 2014 through May 2015	100.00%
Annual Retail Share of Fixed Fuel Costs	$ 90,000
Requested Return on Equity on Capital Costs for Certain Riders	10.65%
Approved Return On Equity	10.20%
Future Commitment to Support the Development of a Large Solar Farm	$ 20,000
Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
PUCO-ordered Fixed Price per MW Day for Customers Who Switch During ESP Period | $ / MWD	188.88
Reliability Pricing Model Rate per MW Day in Effect through May 2014 | $ / MWD	34
Reliability Pricing Model Rate per MW Day in Effect from June 2014 through May 2015 | $ / MWD	150
Retail Stability Rider through May 2014 ($ Per MWh) | $ / MWh	3.50
Retail Stability Rider for the Period June 2014 through May 2015 ($ per MWh) | $ / MWh	4
Amount of Retail Stability Rider Applied to the Deferred Capacity Costs ($ per MWh) | $ / MWh	1
Intended Retail Stability Rider Rate to be Continued Until Capacity Deferral Balance is Collected ($ per MWh) | $ / MWh	4
Retail Stability Rider Rate to be Continued Until Capacity Deferral Balance is Collected as Ordered by the PUCO ($ per MWh) | $ / MWh	4
Deferred Capacity Costs Recovery Period as Ordered by PUCO (in months)	32 months
Percentage of Standard Service Offer Load Which Registrant Conducted Energy Only Auctions for Delivery from April 2014 through May 2015	100.00%
Annual Retail Share of Fixed Fuel Costs	$ 90,000
Requested Return on Equity on Capital Costs for Certain Riders	10.65%
Approved Return On Equity	10.20%
Future Commitment to Support the Development of a Large Solar Farm	$ 20,000
Ohio Fuel Adjustment Clause Audit - 2009 [Member]
Public Utilities, General Disclosures [Line Items]
2008 Coal Contract Settlement Proceeds to be Applied to Deferred Fuel Balance as Originally Ordered by the PUCO	65,000
Net Favorable Fuel Adjustment Recorded in 2012 Based on Fuel Adjustment Clause Audit Rehearing	30,000
Ohio Fuel Adjustment Clause Audit - 2009 [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2008 Coal Contract Settlement Proceeds to be Applied to Deferred Fuel Balance as Originally Ordered by the PUCO	65,000
Net Favorable Fuel Adjustment Recorded in 2012 Based on Fuel Adjustment Clause Audit Rehearing	30,000
Special Rate Mechanism For Ormet [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Approved in the Economic Development Rider Filing	39,000
Remaining Ormet Deferral Allowed to be Requested Upon PUCO Adoption of Ormet Stipulation Agreement	10,000
Amount of Remaining Foregone Revenues Objected to by an Intervenor	5,000
Deferred Fuel Adjustment Clause Related to Ormet Interim Arrangement as of September 2009	64,000
Unrecognized Equity Carrying Costs Related to Ormet Interim Arrangement as of September 2009	2,000
Special Rate Mechanism For Ormet [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount of Foregone Revenues to be Collected Through the Economic Development Rider as Approved in the Economic Development Rider Filing	39,000
Remaining Ormet Deferral Allowed to be Requested Upon PUCO Adoption of Ormet Stipulation Agreement	10,000
Amount of Remaining Foregone Revenues Objected to by an Intervenor	5,000
Deferred Fuel Adjustment Clause Related to Ormet Interim Arrangement as of September 2009	64,000
Unrecognized Equity Carrying Costs Related to Ormet Interim Arrangement as of September 2009	2,000
Transmission Distribution and Storage System Improvement Charge (TDSIC) [Member]
Public Utilities, General Disclosures [Line Items]
Estimated Cost Of Capital Improvements And Associated Operation And Maintenance Expenses	$ 787,000
Percentage Of Approved Project Costs To Be Included In Proposed Rider	80.00%
Remaining Percentage Of Approved Project Costs To Be Included In Next General Rate Case	20.00%
Reduction to the Estimated Cost of Capital Improvements and Associated Operation and Maintenance Expenses	$ 117,000
Transmission Distribution and Storage System Improvement Charge (TDSIC) [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Estimated Cost Of Capital Improvements And Associated Operation And Maintenance Expenses	$ 787,000
Percentage Of Approved Project Costs To Be Included In Proposed Rider	80.00%
Remaining Percentage Of Approved Project Costs To Be Included In Next General Rate Case	20.00%
Reduction to the Estimated Cost of Capital Improvements and Associated Operation and Maintenance Expenses	$ 117,000
Virginia Regulatory Asset Proceeding - 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Amounts Of Regulatory Assets Under Review In Separate Proceeding	12,000
Virginia Regulatory Asset Proceeding - 2015 [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amounts Of Regulatory Assets Under Review In Separate Proceeding	$ 12,000
West Virginia Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return On Equity	9.75%
Requested Base Rate Increase	$ 181,000
Requested Return on Equity	10.62%
Requested Annual Amortization of Certain Deferred Costs	$ 89,000
Requested Annual Vegetation Management Rider	45,000
Approved Base Rate Increase	99,000
Amount of Annual Delayed Customer Billing to Residential Customers	25,000
Approved Annual Vegetation Management Rider	45,000
Approved Annual Amortization Of Certain Deferred Costs	$ 89,000
West Virginia Base Rate Case [Member] | Appalachian Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Approved Return On Equity	9.75%
Requested Base Rate Increase	$ 156,000
Requested Return on Equity	10.62%
Requested Annual Amortization of Certain Deferred Costs	$ 77,000
Requested Annual Vegetation Management Rider	38,000
Approved Base Rate Increase	85,000
Amount of Annual Delayed Customer Billing to Residential Customers	22,000
Approved Annual Vegetation Management Rider	38,000
Approved Annual Amortization Of Certain Deferred Costs	77,000
Deferred Capacity Costs [Member] | Ohio Electric Security Plan Filing [Member]
Public Utilities, General Disclosures [Line Items]
Capacity Deferral Balance as of May 2015 Subject to Audit by the PUCO	444,000
Regulatory Assets, Noncurrent	432,000
Deferred Capacity Costs [Member] | Ohio Electric Security Plan Filing [Member] | Ohio Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Capacity Deferral Balance as of May 2015 Subject to Audit by the PUCO	444,000
Regulatory Assets, Noncurrent	432,000
Big Sandy Plant, Unit 2 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant	$ 194,000
Amortization Period of Approved Regulatory Assets Related to Plant Retirement	25 years
Tanners Creek Plant, Units 1 - 4 [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant	$ 265,000
Amortization Period of Approved Regulatory Assets Related to Plant Retirement	29 years
Amount Reclassified as Regulatory Assets Upon Plant Retirement Currently Not Being Amortized	$ 38,000
Tanners Creek Plant, Units 1 - 4 [Member] | Indiana Michigan Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Amount Reclassified as Regulatory Assets Upon Retirement of the Plant	$ 265,000
Amortization Period of Approved Regulatory Assets Related to Plant Retirement	29 years
Amount Reclassified as Regulatory Assets Upon Plant Retirement Currently Not Being Amortized	$ 38,000
Minimum [Member] | Kentucky 2014 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Net Increase to Rates	20,000
Intervenor Recommended Increase to Rider Rates	55,000
Intervenor Recommended Decrease in Annual Base Rates	$ 35,000
Intervenor Recommended Return On Common Equity Range	8.65%
Maximum [Member] | Kentucky 2014 Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
Intervenor Recommended Net Increase to Rates	$ 26,000
Intervenor Recommended Increase to Rider Rates	63,000
Intervenor Recommended Decrease in Annual Base Rates	$ 37,000
Intervenor Recommended Return On Common Equity Range	8.75%

Rate Matters - West Companies (

Rate Matters - West Companies (Details) - USD ($) $ in Thousands	1 Months Ended	6 Months Ended
	Jul. 23, 2015	Jun. 30, 2015	Dec. 31, 2014
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 3,651,000	$ 3,218,000
Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		244,404	204,753
Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		$ 577,984	$ 471,980
Louisiana 2012 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		29.00%
Net Increase in Louisiana Total Rates per the Settlement Agreement		$ 2,000
Base Rate Increase per the Settlement Agreement		85,000
Fuel Rate Decrease per the Settlement Agreement		$ 83,000
Return on Common Equity per the Settlement Agreement		10.00%
Reduction to Requested Revenue Increase as Approved in Stipulation Agreement		$ 3,000
Louisiana 2012 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Louisiana Jurisdictional Share of the Turk Plant		29.00%
Net Increase in Louisiana Total Rates per the Settlement Agreement		$ 2,000
Base Rate Increase per the Settlement Agreement		85,000
Fuel Rate Decrease per the Settlement Agreement		$ 83,000
Return on Common Equity per the Settlement Agreement		10.00%
Reduction to Requested Revenue Increase as Approved in Stipulation Agreement		$ 3,000
Louisiana 2014 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		5,000
Additional Requested Annual Increase		15,000
Requested Total Annual Increase		20,000
Amount of Interim Rates Implemented in January 2015 as Approved in Partial Settlement Agreement		15,000
Louisiana 2014 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		5,000
Additional Requested Annual Increase		15,000
Requested Total Annual Increase		20,000
Amount of Interim Rates Implemented in January 2015 as Approved in Partial Settlement Agreement		15,000
Louisiana 2015 Formula Rate Filing [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		14,000
Louisiana 2015 Formula Rate Filing [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase		14,000
Oklahoma Base Rate Case - 2014 [Member]
Public Utilities, General Disclosures [Line Items]
Fourteen Months Of Revenues Beginning November 2014 Related To Advanced Metering Costs As Approved In Stipulation Agreement		24,000
2016 Revenues Related To Advanced Metering Costs As Approved In Stipulation Agreement		$ 27,000
Return On Common Equity For AFUDC And Factoring As Approved In Stipulation Agreement		9.85%
Oklahoma Base Rate Case - 2014 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Fourteen Months Of Revenues Beginning November 2014 Related To Advanced Metering Costs As Approved In Stipulation Agreement		$ 24,000
2016 Revenues Related To Advanced Metering Costs As Approved In Stipulation Agreement		$ 27,000
Return On Common Equity For AFUDC And Factoring As Approved In Stipulation Agreement		9.85%
Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 4 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		$ 95,000
Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 4 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		95,000
Texas Base Rate Case [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances		114,000
Resulting Approved Base Rate Increase		52,000
Texas Base Rate Case [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
2013 Reversal of Previously Recorded Regulatory Disallowances		114,000
Resulting Approved Base Rate Increase		52,000
Texas Base Rate Case [Member] | Welsh Plant, Unit 2 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		83,000
Texas Base Rate Case [Member] | Welsh Plant, Unit 2 [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		83,000
Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		600,000
Construction Work in Progress		256,000
Remaining Contractual Construction Obligations		89,000
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		600,000
Construction Work in Progress		256,000
Remaining Contractual Construction Obligations		89,000
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		484,000
Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Welsh Plant, Units 1 and 3 [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Property, Plant and Equipment, Net		484,000
Subsequent Event [Member] | Oklahoma Base Rate Case - 2015 [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase	$ 137,000
Requested Base Rate Increase	89,000
Amount of Increased Depreciation Expense Requested	48,000
Amount of Increase Related to Environmental Controls	44,000
Amount Of Requested Increase Related To Environmental Consumable Costs In Fuel Adjustment Clause	$ 4,000
Requested Return on Equity	10.50%
Future Incremental Purchased Capacity and Energy Costs Related to Environmental Projects	$ 35,000
Subsequent Event [Member] | Oklahoma Base Rate Case - 2015 [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Requested Annual Increase	137,000
Requested Base Rate Increase	89,000
Amount of Increased Depreciation Expense Requested	48,000
Amount of Increase Related to Environmental Controls	44,000
Amount Of Requested Increase Related To Environmental Consumable Costs In Fuel Adjustment Clause	$ 4,000
Requested Return on Equity	10.50%
Future Incremental Purchased Capacity and Energy Costs Related to Environmental Projects	$ 35,000
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 and Comanche Plant [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		140,000
Environmental Controls Projects [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 and Comanche Plant [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Construction Work in Progress		140,000
Environmental Controls Projects [Member] | Subsequent Event [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 and Comanche Plant [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs	219,000
Environmental Controls Projects [Member] | Subsequent Event [Member] | Oklahoma Base Rate Case - 2015 [Member] | Northeastern Plant, Unit 3 and Comanche Plant [Member] | Public Service Co Of Oklahoma [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs	$ 219,000
Mercury and Air Toxic Standards [Member] | Welsh Plant, Units 1 and 3 - Environmental Projects [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		410,000
Mercury and Air Toxic Standards [Member] | Welsh Plant, Units 1 and 3 - Environmental Projects [Member] | Southwestern Electric Power Co [Member]
Public Utilities, General Disclosures [Line Items]
Projected Capital Costs		$ 410,000

Commitments, Guarantees and C46

Commitments, Guarantees and Contingencies (Details) - Jun. 30, 2015 - USD ($) $ in Thousands	Total
Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit	$ 61,000
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported	477,000
Bilateral Letters of Credit	483,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Revolving Credit Facilities	3,500,000
Letters of Credit Limit	1,200,000
Maximum Future Payments for Letters of Credit	61,000
Uncommitted Facility	100,000
Maximum Future Payments for Letters of Credit Issued Under the Uncommitted Facility	100,000
Variable Rate PCBs Supported	477,000
Bilateral Letters of Credit	483,000
Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	30,000
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Max Potential Loss on Master Lease Agreements	30,000
Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount	115,000
Estimated Final Cost Mine Reclamation	58,000
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs	65,000
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent	16,000
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	49,000
Indiana Michigan Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit	35
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported	77,000
Bilateral Letters of Credit	77,886
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Future Payments for Letters of Credit	35
Variable Rate PCBs Supported	77,000
Bilateral Letters of Credit	77,886
Indiana Michigan Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	3,323
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Max Potential Loss on Master Lease Agreements	3,323
Future Minimum Lease Obligation for Remaining Railcars	$ 11,000
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
Southwestern Electric Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	2,825
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Max Potential Loss on Master Lease Agreements	2,825
Future Minimum Lease Obligation for Remaining Railcars	$ 12,000
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
Southwestern Electric Power Co [Member] | Guarantees of Third Party Obligations [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Guarantees of Mine Reclamation, Amount	115,000
Estimated Final Cost Mine Reclamation	58,000
Total Amount Collected through a Rider for Final Mine Closure and Reclamation Costs	65,000
Amount Collected through a Rider for Final Mine Closure - Other Liabilities Noncurrent	16,000
Amount Collected through a Rider for Final Mine Closure - ARO Noncurrent	49,000
Ohio Power Co [Member] | Letters of Credit [Member]
Maximum Future Payments for Letters of Credit [Abstract]
Maximum Future Payments for Letters of Credit	4,200
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Maximum Future Payments for Letters of Credit	4,200
Ohio Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	5,618
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Max Potential Loss on Master Lease Agreements	5,618
Appalachian Power Co [Member] | Letters of Credit [Member]
Pollution Control Bonds Supported by Bilateral Letters of Credit [Abstract]
Variable Rate PCBs Supported	229,650
Bilateral Letters of Credit	232,293
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Variable Rate PCBs Supported	229,650
Bilateral Letters of Credit	232,293
Appalachian Power Co [Member] | Master Lease Agreements [Member]
Maximum Potential Loss on Master Lease Agreements [Abstract]
Max Potential Loss on Master Lease Agreements	4,864
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Max Potential Loss on Master Lease Agreements	4,864
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	2,428
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Max Potential Loss on Master Lease Agreements	2,428
Superfund and State Remediation [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision	9,000
Superfund and State Remediation [Member] | Indiana Michigan Power Co [Member]
Commitments, Guarantees and Contingencies (Textuals) [Abstract]
Expense Recorded Due to Remediation Work Remaining Provision	$ 9,000

Benefit Plans (Details)

Benefit Plans (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Pension Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	$ 24,000	$ 18,000	$ 47,000	$ 36,000
Interest Cost	52,000	56,000	103,000	111,000
Expected Return on Plan Assets	(68,000)	(65,000)	(137,000)	(131,000)
Amortization of Prior Service Cost (Credit)	0	0	1,000	1,000
Amortization of Net Actuarial Loss	26,000	31,000	53,000	62,000
Net Periodic Benefit Cost (Credit)	34,000	40,000	67,000	79,000
Pension Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2,175	1,759	4,350	3,518
Interest Cost	6,679	7,406	13,358	14,812
Expected Return on Plan Assets	(8,746)	(8,481)	(17,491)	(16,963)
Amortization of Prior Service Cost (Credit)	45	49	90	99
Amortization of Net Actuarial Loss	3,474	4,148	6,947	8,296
Net Periodic Benefit Cost (Credit)	3,627	4,881	7,254	9,762
Pension Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	3,217	2,517	6,434	5,034
Interest Cost	6,115	6,574	12,230	13,147
Expected Return on Plan Assets	(8,116)	(7,748)	(16,232)	(15,496)
Amortization of Prior Service Cost (Credit)	46	48	91	97
Amortization of Net Actuarial Loss	3,144	3,646	6,289	7,292
Net Periodic Benefit Cost (Credit)	4,406	5,037	8,812	10,074
Pension Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	1,672	1,285	3,344	2,570
Interest Cost	5,070	5,526	10,140	11,052
Expected Return on Plan Assets	(6,878)	(6,606)	(13,756)	(13,213)
Amortization of Prior Service Cost (Credit)	35	39	70	78
Amortization of Net Actuarial Loss	2,644	3,105	5,288	6,211
Net Periodic Benefit Cost (Credit)	2,543	3,349	5,086	6,698
Pension Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	1,599	1,302	3,198	2,604
Interest Cost	2,732	3,014	5,463	6,028
Expected Return on Plan Assets	(3,786)	(3,651)	(7,572)	(7,302)
Amortization of Prior Service Cost (Credit)	63	74	126	148
Amortization of Net Actuarial Loss	1,417	1,688	2,834	3,376
Net Periodic Benefit Cost (Credit)	2,025	2,427	4,049	4,854
Pension Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	2,082	1,654	4,163	3,309
Interest Cost	2,932	3,162	5,864	6,325
Expected Return on Plan Assets	(4,008)	(3,857)	(8,016)	(7,714)
Amortization of Prior Service Cost (Credit)	77	88	154	175
Amortization of Net Actuarial Loss	1,507	1,762	3,014	3,523
Net Periodic Benefit Cost (Credit)	2,590	2,809	5,179	5,618
Other Postretirement Benefit Plans [Member]
Components of Net Periodic Benefit Cost
Service Cost	3,000	3,000	6,000	7,000
Interest Cost	14,000	17,000	28,000	34,000
Expected Return on Plan Assets	(27,000)	(28,000)	(55,000)	(56,000)
Amortization of Prior Service Cost (Credit)	(17,000)	(17,000)	(34,000)	(34,000)
Amortization of Net Actuarial Loss	4,000	6,000	9,000	11,000
Net Periodic Benefit Cost (Credit)	(23,000)	(19,000)	(46,000)	(38,000)
Other Postretirement Benefit Plans [Member] | Appalachian Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	285	362	571	724
Interest Cost	2,585	3,197	5,169	6,394
Expected Return on Plan Assets	(4,529)	(4,633)	(9,058)	(9,266)
Amortization of Prior Service Cost (Credit)	(2,512)	(2,512)	(5,025)	(5,025)
Amortization of Net Actuarial Loss	899	1,145	1,799	2,291
Net Periodic Benefit Cost (Credit)	(3,272)	(2,441)	(6,544)	(4,882)
Other Postretirement Benefit Plans [Member] | Indiana Michigan Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	407	487	813	974
Interest Cost	1,592	1,910	3,184	3,819
Expected Return on Plan Assets	(3,304)	(3,363)	(6,608)	(6,727)
Amortization of Prior Service Cost (Credit)	(2,356)	(2,356)	(4,711)	(4,711)
Amortization of Net Actuarial Loss	507	592	1,013	1,184
Net Periodic Benefit Cost (Credit)	(3,154)	(2,730)	(6,309)	(5,461)
Other Postretirement Benefit Plans [Member] | Ohio Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	215	257	431	513
Interest Cost	1,615	1,900	3,230	3,801
Expected Return on Plan Assets	(3,378)	(3,380)	(6,754)	(6,760)
Amortization of Prior Service Cost (Credit)	(1,730)	(1,730)	(3,461)	(3,461)
Amortization of Net Actuarial Loss	518	595	1,035	1,190
Net Periodic Benefit Cost (Credit)	(2,760)	(2,358)	(5,519)	(4,717)
Other Postretirement Benefit Plans [Member] | Public Service Co Of Oklahoma [Member]
Components of Net Periodic Benefit Cost
Service Cost	169	210	339	420
Interest Cost	759	894	1,518	1,787
Expected Return on Plan Assets	(1,577)	(1,575)	(3,154)	(3,150)
Amortization of Prior Service Cost (Credit)	(1,072)	(1,073)	(2,145)	(2,145)
Amortization of Net Actuarial Loss	241	277	483	554
Net Periodic Benefit Cost (Credit)	(1,480)	(1,267)	(2,959)	(2,534)
Other Postretirement Benefit Plans [Member] | Southwestern Electric Power Co [Member]
Components of Net Periodic Benefit Cost
Service Cost	210	253	421	506
Interest Cost	838	998	1,675	1,996
Expected Return on Plan Assets	(1,736)	(1,754)	(3,471)	(3,508)
Amortization of Prior Service Cost (Credit)	(1,289)	(1,289)	(2,578)	(2,578)
Amortization of Net Actuarial Loss	266	308	532	617
Net Periodic Benefit Cost (Credit)	$ (1,711)	$ (1,484)	$ (3,421)	$ (2,967)

Business Segments (Details)

Business Segments (Details) - USD ($) $ in Millions		3 Months Ended			6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014		Jun. 30, 2015	Jun. 30, 2014		Dec. 31, 2014
Reportable Segment Information
Revenues		$ 3,942	$ 4,044		$ 8,650	$ 8,692
NET INCOME (LOSS)		431	391		1,062	952
Balance Sheet Information
Total Property, Plant and Equipment		64,602			64,602			$ 64,305
Accumulated Depreciation and Amortization		19,589			19,589			20,188
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		45,013			45,013			44,117
Total Assets		60,938			60,938			59,633
Long-term Debt Due Within One Year - Affiliated		0			0			0
Long-term Debt Due Within One Year		1,817			1,817			2,503
Long-term Debt - Affiliated		0			0			0
Long-term Debt		17,761			17,761			16,181
Total Long-term Debt Outstanding		19,578			19,578			18,684
Reconciling Adjustments [Member]
Reportable Segment Information
NET INCOME (LOSS)		0	0		0	0
Balance Sheet Information
Total Property, Plant and Equipment	[1]	(279)			(279)			(272)
Accumulated Depreciation and Amortization	[1]	(105)			(105)			(99)
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[1]	(174)			(174)			(173)
Total Assets	[1],[2]	(20,788)			(20,788)			(20,346)
Long-term Debt Due Within One Year - Affiliated		0			0			(197)
Long-term Debt Due Within One Year		0			0			0
Long-term Debt - Affiliated		(52)			(52)			(52)
Long-term Debt		0			0			0
Total Long-term Debt Outstanding		(52)			(52)			(249)
Vertically Integrated Utilities [Member]
Reportable Segment Information
Sales Revenue, Net		2,159	2,236	[3]	4,646	4,785	[3]
Revenues		2,183	2,252		4,688	4,838
NET INCOME (LOSS)		208	155		508	434
Balance Sheet Information
Total Property, Plant and Equipment		39,561			39,561			39,402
Accumulated Depreciation and Amortization		12,343			12,343			12,773
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		27,218			27,218			26,629
Total Assets		35,316			35,316			33,750
Long-term Debt Due Within One Year - Affiliated		0			0			111
Long-term Debt Due Within One Year		894			894			1,352
Long-term Debt - Affiliated		20			20			20
Long-term Debt		10,146			10,146			8,634
Total Long-term Debt Outstanding		11,060			11,060			10,117
Vertically Integrated Utilities [Member] | Significant Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net		24	16	[3]	42	53	[3]
Transmission And Distribution Utilities [Member]
Reportable Segment Information
Sales Revenue, Net		1,008	1,064		2,214	2,225
Revenues		1,061	1,134		2,331	2,349
NET INCOME (LOSS)		78	90		175	187
Balance Sheet Information
Total Property, Plant and Equipment		13,506			13,506			13,024
Accumulated Depreciation and Amortization		3,565			3,565			3,481
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		9,941			9,941			9,543
Total Assets		14,351			14,351			14,495
Long-term Debt Due Within One Year - Affiliated		0			0			0
Long-term Debt Due Within One Year		678			678			405
Long-term Debt - Affiliated		0			0			0
Long-term Debt		4,729			4,729			5,256
Total Long-term Debt Outstanding		5,407			5,407			5,661
Transmission And Distribution Utilities [Member] | Significant Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net		53	70		117	124
AEP Transmission Holdco [Member]
Reportable Segment Information
Sales Revenue, Net		25	21		47	33
Revenues		99	57		157	85
NET INCOME (LOSS)		65	47		102	71
Balance Sheet Information
Total Property, Plant and Equipment		3,275			3,275			2,714
Accumulated Depreciation and Amortization		34			34			25
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		3,241			3,241			2,689
Total Assets		4,036			4,036			3,575
Long-term Debt Due Within One Year - Affiliated		0			0			0
Long-term Debt Due Within One Year		0			0			0
Long-term Debt - Affiliated		0			0			0
Long-term Debt		1,315			1,315			1,153
Total Long-term Debt Outstanding		1,315			1,315			1,153
AEP Transmission Holdco [Member] | Significant Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net		74	36		110	52
Generation And Marketing [Member]
Reportable Segment Information
Sales Revenue, Net		628	573	[3]	1,487	1,394	[3]
Revenues		801	913		1,971	2,164
NET INCOME (LOSS)		82	98		269	261
Balance Sheet Information
Total Property, Plant and Equipment		7,456			7,456			8,394
Accumulated Depreciation and Amortization		3,344			3,344			3,603
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		4,112			4,112			4,791
Total Assets		5,668			5,668			6,329
Long-term Debt Due Within One Year - Affiliated		0			0			86
Long-term Debt Due Within One Year		240			240			740
Long-term Debt - Affiliated		32			32			32
Long-term Debt		648			648			217
Total Long-term Debt Outstanding		920			920			1,075
Generation And Marketing [Member] | Significant Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net		173	340	[3]	484	770	[3]
AEP River Operations [Member]
Reportable Segment Information
Sales Revenue, Net		115	140		243	286
Revenues		128	160		267	325
NET INCOME (LOSS)		1	3		12	6
Balance Sheet Information
Total Property, Plant and Equipment		726			726			700
Accumulated Depreciation and Amortization		227			227			217
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET		499			499			483
Total Assets		756			756			749
Long-term Debt Due Within One Year - Affiliated		0			0			0
Long-term Debt Due Within One Year		3			3			3
Long-term Debt - Affiliated		0			0			0
Long-term Debt		79			79			80
Total Long-term Debt Outstanding		82			82			83
AEP River Operations [Member] | Significant Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net		13	20		24	39
All Other [Member]
Reportable Segment Information
Sales Revenue, Net	[4]	7	10		13	20
Revenues	[4]	24	22		50	48
NET INCOME (LOSS)	[4]	(3)	(2)		(4)	(7)
Balance Sheet Information
Total Property, Plant and Equipment	[4]	357			357			343
Accumulated Depreciation and Amortization	[4]	181			181			188
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	[4]	176			176			155
Total Assets	[4]	21,599			21,599			21,081
Long-term Debt Due Within One Year - Affiliated	[4]	0			0			0
Long-term Debt Due Within One Year	[4]	2			2			3
Long-term Debt - Affiliated	[4]	0			0			0
Long-term Debt	[4]	844			844			841
Total Long-term Debt Outstanding	[4]	846			846			$ 844
All Other [Member] | Significant Reconciling Items [Member]
Reportable Segment Information
Sales Revenue, Net	[4]	17	12		37	28
Consolidation, Eliminations [Member]
Reportable Segment Information
Sales Revenue, Net	[5]	0	0		0	(51)
Revenues		(354)	(494)		(814)	(1,117)
Consolidation, Eliminations [Member] | Reconciling Adjustments [Member]
Reportable Segment Information
Sales Revenue, Net		$ (354)	$ (494)		$ (814)	$ (1,066)
[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 AEP's investments in subsidiary companies.
[3]	Includes the impact of 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.
[4]	Corporate and Other primarily includes the purchasing of receivables from certain AEP utility subsidiaries. This segment also includes Parent's guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs.
[5]	Reconciling Adjustments for External Customers primarily include eliminations as a result of corporate separation in Ohio.

Derivatives and Hedging (Detail

Derivatives and Hedging (Details) gal in Thousands, T in Thousands, MWh in Thousands, MMBTU in Thousands, $ in Thousands		3 Months Ended			6 Months Ended			12 Months Ended
		Jun. 30, 2015USD ($)MWhMMBTUTgal		Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)MWhMMBTUTgal		Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)MWhMMBTUTgal
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		$ 3,000			$ 3,000			$ 4,000
Cash Collateral Paid Netted Against Risk Management Liabilities		27,000			27,000			35,000
Fair Value of Derivative Instruments
Current Risk Management Assets		172,000			172,000			178,000
Long-term Risk Management Assets		363,000			363,000			294,000
Total Assets		535,000			535,000			472,000
Current Risk Management Liabilities		78,000			78,000			92,000
Long-term Risk Management Liabilities		174,000			174,000			131,000
Total Liabilities		252,000			252,000			223,000
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		64,000		$ 49,000	120,000		$ 188,000
Gain (Loss) on Hedging Instruments
Gain (Loss) on Fair Value Hedging Instruments		1,000		2,000	6,000		4,000
Gain (Loss) on Fair Value Portion of Long Term Debt		(1,000)		(2,000)	(6,000)		(4,000)
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[1]	10,000			10,000			16,000
Hedging Liabilities	[1]	20,000			20,000			15,000
AOCI Gain (Loss) Net of Tax		(23,000)			(23,000)			(18,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					$ 3,000			2,000
Maximum Term for Exposure to Variability of Future Cash Flows					90 months
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		0			$ 0			0
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0			0			0
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		31,000			31,000			36,000
Amount of Collateral Attributable to Other Contracts	[2]	304,000			304,000			281,000
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		287,000			287,000			235,000
Amount of Cash Collateral Posted		5,000			5,000			9,000
Additional Settlement Liability if Cross Default Provision is Triggered		225,000			225,000			178,000
Derivatives and Hedging (Textuals) [Abstract]
Cash Collateral Received Netted Against Risk Management Assets		3,000			3,000			4,000
Cash Collateral Paid Netted Against Risk Management Liabilities		27,000			$ 27,000			35,000
Maximum Term for Exposure to Variability of Future Cash Flows					90 months
Appalachian Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			$ 0			68
Cash Collateral Paid Netted Against Risk Management Liabilities		915			915			98
Fair Value of Derivative Instruments
Current Risk Management Assets		38,877			38,877			23,792
Long-term Risk Management Assets		3,002			3,002			4,891
Current Risk Management Liabilities		9,159			9,159			11,017
Long-term Risk Management Liabilities		1,448			1,448			2,057
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		28,000		14,902	$ 31,591		52,085
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		0			$ 0			0
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0			0			0
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		3,211			3,211			6,339
Amount of Collateral Attributable to Other Contracts		987			987			74
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		6,795			6,795			9,043
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		6,715			6,715			9,012
Derivatives and Hedging (Textuals) [Abstract]
Cash Collateral Received Netted Against Risk Management Assets		0			0			68
Cash Collateral Paid Netted Against Risk Management Liabilities		915			$ 915			98
Maximum Term for Exposure to Variability of Future Cash Flows
Indiana Michigan Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			$ 0			163
Cash Collateral Paid Netted Against Risk Management Liabilities		428			428			47
Fair Value of Derivative Instruments
Current Risk Management Assets		16,514			16,514			22,328
Long-term Risk Management Assets		2,026			2,026			3,317
Current Risk Management Liabilities		4,493			4,493			5,223
Long-term Risk Management Liabilities		982			982			1,395
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		10,292		9,816	$ 9,892		34,068
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		0			$ 0			0
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0			0			0
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		2,178			2,178			4,299
Amount of Collateral Attributable to Other Contracts		215			215			47
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		4,609			4,609			6,134
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		4,554			4,554			6,113
Derivatives and Hedging (Textuals) [Abstract]
Cash Collateral Received Netted Against Risk Management Assets		0			0			163
Cash Collateral Paid Netted Against Risk Management Liabilities		428			$ 428			47
Maximum Term for Exposure to Variability of Future Cash Flows
Ohio Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			$ 0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		121			121			102
Fair Value of Derivative Instruments
Current Risk Management Assets		0			0			7,242
Long-term Risk Management Assets		44,056			44,056			45,102
Current Risk Management Liabilities		2,010			2,010			1,943
Long-term Risk Management Liabilities		4,573			4,573			3,013
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(7,462)		6,460	$ (3,082)		41,559
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		0			$ 0			0
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0			0			0
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		0			0			0
Amount of Collateral Attributable to Other Contracts		0			0			0
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0			0			0
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0			0			0
Derivatives and Hedging (Textuals) [Abstract]
Cash Collateral Received Netted Against Risk Management Assets		0			0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		121			$ 121			102
Maximum Term for Exposure to Variability of Future Cash Flows
Public Service Co Of Oklahoma [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			$ 0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		115			115			54
Fair Value of Derivative Instruments
Current Risk Management Assets		1,731			1,731			0
Long-term Risk Management Assets		29			29			0
Current Risk Management Liabilities		129			129			918
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		7,076		(318)	$ 6,046		449
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		0			$ 0			0
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0			0			0
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		244			244			693
Amount of Collateral Attributable to Other Contracts		6,783			6,783			4,111
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0			0			0
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0			0			0
Derivatives and Hedging (Textuals) [Abstract]
Cash Collateral Received Netted Against Risk Management Assets		0			0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		115			$ 115			54
Maximum Term for Exposure to Variability of Future Cash Flows
Southwestern Electric Power Co [Member]
Cash Collateral Netting
Cash Collateral Received Netted Against Risk Management Assets		0			$ 0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		134			134			62
Fair Value of Derivative Instruments
Current Risk Management Assets		2,077			2,077			31
Long-term Risk Management Assets		33			33			0
Current Risk Management Liabilities		2,523			2,523			1,082
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		11,321		(1,114)	$ 11,490		242
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Maximum Term for Exposure to Variability of Future Cash Flows
Collateral Triggering Events [Abstract]
Fair Value of Contracts with Credit Downgrade Triggers		0			$ 0			0
Amount of Collateral AEP Subsidiaries Would Have been Required to Post for Derivative Contracts as well as Derivative and Non-Derivative Contracts Subject to the Same Master Netting Arrangement		0			0			0
Amount of Collateral AEP Subsidiaries Would Have Been Required to Post Attributable to RTOs and ISOs		293			293			877
Amount of Collateral Attributable to Other Contracts		210			210			166
Liabilities for Contracts with Cross Default Provisions Prior to Contractual Netting Arrangements		0			0			0
Amount of Cash Collateral Posted		0			0			0
Additional Settlement Liability if Cross Default Provision is Triggered		0			0			0
Derivatives and Hedging (Textuals) [Abstract]
Cash Collateral Received Netted Against Risk Management Assets		0			0			0
Cash Collateral Paid Netted Against Risk Management Liabilities		134			$ 134			62
Maximum Term for Exposure to Variability of Future Cash Flows
Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Total Assets	[3]	523,000	[4]		$ 523,000	[4]		453,000	[5]
Total Liabilities	[3]	227,000	[4]		227,000	[4]		199,000	[5]
Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[6],[7]	41,879			41,879			28,683
Total Liabilities	[6],[7]	10,607			10,607			13,074
Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[6],[7]	18,540			18,540			25,645
Total Liabilities	[6],[7]	5,475			5,475			6,618
Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[6],[7]	44,056			44,056			52,344
Total Liabilities	[6],[7]	6,583			6,583			4,956
Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Total Assets	[6],[7]	1,760			1,760			0
Total Liabilities	[6],[7]	129			129			918
Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Total Assets	[6],[7]	2,110			2,110			31
Total Liabilities	[6],[7]	2,523			2,523			1,082
Commodity [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[1]	10,000			10,000			16,000
Hedging Liabilities	[1]	19,000			19,000			14,000
AOCI Gain (Loss) Net of Tax		(5,000)			(5,000)			1,000
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					4,000			4,000
Derivatives and Hedging (Textuals) [Abstract]
Cross Default Provisions Maximum Third Party Obligation Amount		50,000			50,000			50,000
Commodity [Member] | Appalachian Power Co [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		0			0			0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0			0
Commodity [Member] | Indiana Michigan Power Co [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		0			0			0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0			0
Commodity [Member] | Ohio Power Co [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		0			0			0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0			0
Commodity [Member] | Public Service Co Of Oklahoma [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		0			0			0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0			0
Commodity [Member] | Southwestern Electric Power Co [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		0			0			0
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					0			0
Commodity [Member] | Risk Management Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	390,000			390,000			392,000
Long-term Risk Management Assets	[9]	451,000			451,000			367,000
Total Assets	[9]	841,000			841,000			759,000
Current Risk Management Liabilities	[9]	311,000			311,000			329,000
Long-term Risk Management Liabilities	[9]	258,000			258,000			208,000
Total Liabilities	[9]	569,000			569,000			537,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	272,000			272,000			222,000
Commodity [Member] | Risk Management Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	52,015			52,015			32,903
Long-term Risk Management Assets	[10]	3,286			3,286			5,159
Total Assets	[10]	55,301			55,301			38,062
Current Risk Management Liabilities	[10]	23,210			23,210			20,161
Long-term Risk Management Liabilities	[10]	1,734			1,734			2,322
Total Liabilities	[10]	24,944			24,944			22,483
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	30,357			30,357			15,579
Commodity [Member] | Risk Management Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	26,147			26,147			28,545
Long-term Risk Management Assets	[10]	2,219			2,219			3,499
Total Assets	[10]	28,366			28,366			32,044
Current Risk Management Liabilities	[10]	14,553			14,553			11,326
Long-term Risk Management Liabilities	[10]	1,176			1,176			1,575
Total Liabilities	[10]	15,729			15,729			12,901
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	12,637			12,637			19,143
Commodity [Member] | Risk Management Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	70			70			7,242
Long-term Risk Management Assets	[10]	44,056			44,056			45,102
Total Assets	[10]	44,126			44,126			52,344
Current Risk Management Liabilities	[10]	2,201			2,201			2,045
Long-term Risk Management Liabilities	[10]	4,573			4,573			3,013
Total Liabilities	[10]	6,774			6,774			5,058
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	37,352			37,352			47,286
Commodity [Member] | Risk Management Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	1,821			1,821			360
Long-term Risk Management Assets	[10]	29			29			0
Total Assets	[10]	1,850			1,850			360
Current Risk Management Liabilities	[10]	334			334			1,332
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	334			334			1,332
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	1,516			1,516			(972)
Commodity [Member] | Risk Management Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	2,183			2,183			471
Long-term Risk Management Assets	[10]	33			33			0
Total Assets	[10]	2,216			2,216			471
Current Risk Management Liabilities	[10]	2,763			2,763			1,584
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	2,763			2,763			1,584
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	(547)			(547)			(1,113)
Commodity [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	22,000			22,000			30,000
Long-term Risk Management Assets	[9]	4,000			4,000			3,000
Total Assets	[9]	26,000			26,000			33,000
Current Risk Management Liabilities	[9]	18,000			18,000			23,000
Long-term Risk Management Liabilities	[9]	17,000			17,000			8,000
Total Liabilities	[9]	35,000			35,000			31,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(9,000)			(9,000)			2,000
Commodity [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Commodity [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Commodity [Member] | Hedging Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Commodity [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Commodity [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Interest Rate and Foreign Currency [Member]
Commodity:
Derivative, Notional Amount		564,000			564,000			815,000
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[1]	0			0			0
Hedging Liabilities	[1]	1,000			1,000			1,000
AOCI Gain (Loss) Net of Tax		(18,000)			(18,000)			(19,000)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,000)			(2,000)
Interest Rate and Foreign Currency [Member] | Appalachian Power Co [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		4,027			4,027			3,896
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					773			275
Interest Rate and Foreign Currency [Member] | Indiana Michigan Power Co [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		(13,871)			(13,871)			(14,406)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,214)			(1,090)
Interest Rate and Foreign Currency [Member] | Ohio Power Co [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		4,916			4,916			5,602
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					1,350			1,372
Interest Rate and Foreign Currency [Member] | Public Service Co Of Oklahoma [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		4,563			4,563			4,943
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					759			759
Interest Rate and Foreign Currency [Member] | Southwestern Electric Power Co [Member]
Impact of Cash Flow Hedges on the Condensed Balance Sheet
Hedging Assets	[8]	0			0			0
Hedging Liabilities	[8]	0			0			0
AOCI Gain (Loss) Net of Tax		(9,902)			(9,902)			(11,036)
Portion Expected to be Reclassified to Net Income During the Next Twelve Months					(1,728)			(1,998)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[9]	2,000			2,000			3,000
Long-term Risk Management Assets	[9]	0			0			0
Total Assets	[9]	2,000			2,000			3,000
Current Risk Management Liabilities	[9]	1,000			1,000			1,000
Long-term Risk Management Liabilities	[9]	5,000			5,000			9,000
Total Liabilities	[9]	6,000			6,000			10,000
Total MTM Derivative Contract Net Assets (Liabilities)	[9]	(4,000)			(4,000)			(7,000)
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Interest Rate and Foreign Currency [Member] | Hedging Contracts [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[10]	0			0			0
Long-term Risk Management Assets	[10]	0			0			0
Total Assets	[10]	0			0			0
Current Risk Management Liabilities	[10]	0			0			0
Long-term Risk Management Liabilities	[10]	0			0			0
Total Liabilities	[10]	0			0			0
Total MTM Derivative Contract Net Assets (Liabilities)	[10]	0			0			0
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		414,000			414,000			425,000
Long-term Risk Management Assets		455,000			455,000			370,000
Total Assets		869,000			869,000			795,000
Current Risk Management Liabilities		330,000			330,000			353,000
Long-term Risk Management Liabilities		280,000			280,000			225,000
Total Liabilities		610,000			610,000			578,000
Total MTM Derivative Contract Net Assets (Liabilities)		259,000			259,000			217,000
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		52,015			52,015			32,903
Long-term Risk Management Assets		3,286			3,286			5,159
Total Assets		55,301			55,301			38,062
Current Risk Management Liabilities		23,210			23,210			20,161
Long-term Risk Management Liabilities		1,734			1,734			2,322
Total Liabilities		24,944			24,944			22,483
Total MTM Derivative Contract Net Assets (Liabilities)		30,357			30,357			15,579
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		26,147			26,147			28,545
Long-term Risk Management Assets		2,219			2,219			3,499
Total Assets		28,366			28,366			32,044
Current Risk Management Liabilities		14,553			14,553			11,326
Long-term Risk Management Liabilities		1,176			1,176			1,575
Total Liabilities		15,729			15,729			12,901
Total MTM Derivative Contract Net Assets (Liabilities)		12,637			12,637			19,143
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		70			70			7,242
Long-term Risk Management Assets		44,056			44,056			45,102
Total Assets		44,126			44,126			52,344
Current Risk Management Liabilities		2,201			2,201			2,045
Long-term Risk Management Liabilities		4,573			4,573			3,013
Total Liabilities		6,774			6,774			5,058
Total MTM Derivative Contract Net Assets (Liabilities)		37,352			37,352			47,286
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Public Service Co Of Oklahoma [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		1,821			1,821			360
Long-term Risk Management Assets		29			29			0
Total Assets		1,850			1,850			360
Current Risk Management Liabilities		334			334			1,332
Long-term Risk Management Liabilities		0			0			0
Total Liabilities		334			334			1,332
Total MTM Derivative Contract Net Assets (Liabilities)		1,516			1,516			(972)
Gross Amounts of Risk Management Assets/Liabilities Recognized [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets		2,183			2,183			471
Long-term Risk Management Assets		33			33			0
Total Assets		2,216			2,216			471
Current Risk Management Liabilities		2,763			2,763			1,584
Long-term Risk Management Liabilities		0			0			0
Total Liabilities		2,763			2,763			1,584
Total MTM Derivative Contract Net Assets (Liabilities)		(547)			(547)			(1,113)
Gross Amounts Offset in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[11]	(242,000)			(242,000)			(247,000)
Long-term Risk Management Assets	[11]	(92,000)			(92,000)			(76,000)
Total Assets	[11]	(334,000)			(334,000)			(323,000)
Current Risk Management Liabilities	[11]	(252,000)			(252,000)			(261,000)
Long-term Risk Management Liabilities	[11]	(106,000)			(106,000)			(94,000)
Total Liabilities	[11]	(358,000)			(358,000)			(355,000)
Total MTM Derivative Contract Net Assets (Liabilities)	[11]	24,000			24,000			32,000
Gross Amounts Offset in the Statement of Financial Position [Member] | Appalachian Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	(13,138)			(13,138)			(9,111)
Long-term Risk Management Assets	[12]	(284)			(284)			(268)
Total Assets	[12]	(13,422)			(13,422)			(9,379)
Current Risk Management Liabilities	[12]	(14,051)			(14,051)			(9,144)
Long-term Risk Management Liabilities	[12]	(286)			(286)			(265)
Total Liabilities	[12]	(14,337)			(14,337)			(9,409)
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	915			915			30
Gross Amounts Offset in the Statement of Financial Position [Member] | Indiana Michigan Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	(9,633)			(9,633)			(6,217)
Long-term Risk Management Assets	[12]	(193)			(193)			(182)
Total Assets	[12]	(9,826)			(9,826)			(6,399)
Current Risk Management Liabilities	[12]	(10,060)			(10,060)			(6,103)
Long-term Risk Management Liabilities	[12]	(194)			(194)			(180)
Total Liabilities	[12]	(10,254)			(10,254)			(6,283)
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	428			428			(116)
Gross Amounts Offset in the Statement of Financial Position [Member] | Ohio Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	(70)			(70)			0
Long-term Risk Management Assets	[12]	0			0			0
Total Assets	[12]	(70)			(70)			0
Current Risk Management Liabilities	[12]	(191)			(191)			(102)
Long-term Risk Management Liabilities	[12]	0			0			0
Total Liabilities	[12]	(191)			(191)			(102)
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	121			121			102
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	[12]	(90)			(90)			(360)
Long-term Risk Management Assets	[12]	0			0			0
Total Assets	[12]	(90)			(90)			(360)
Current Risk Management Liabilities	[12]	(205)			(205)			(414)
Long-term Risk Management Liabilities	[12]	0			0			0
Total Liabilities	[12]	(205)			(205)			(414)
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	115			115			54
Gross Amounts Offset in the Statement of Financial Position [Member] | Southwestern Electric Power Co [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[12]	(106)			(106)			(440)
Long-term Risk Management Assets	[12]	0			0			0
Total Assets	[12]	(106)			(106)			(440)
Current Risk Management Liabilities	[12]	(240)			(240)			(502)
Long-term Risk Management Liabilities	[12]	0			0			0
Total Liabilities	[12]	(240)			(240)			(502)
Total MTM Derivative Contract Net Assets (Liabilities)	[12]	134			134			62
Net Amounts of Assets/Liabilities Presented in the Statement of Financial Position [Member]
Fair Value of Derivative Instruments
Current Risk Management Assets	[13]	172,000			172,000			178,000
Long-term Risk Management Assets	[13]	363,000			363,000			294,000
Total Assets	[13]	535,000			535,000			472,000
Current Risk Management Liabilities	[13]	78,000			78,000			92,000
Long-term Risk Management Liabilities	[13]	174,000			174,000			131,000
Total Liabilities	[13]	252,000			252,000			223,000
Total MTM Derivative Contract Net Assets (Liabilities)	[13]	283,000			283,000			249,000
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	[14]	38,877			38,877			23,792
Long-term Risk Management Assets	[14]	3,002			3,002			4,891
Total Assets	[14]	41,879			41,879			28,683
Current Risk Management Liabilities	[14]	9,159			9,159			11,017
Long-term Risk Management Liabilities	[14]	1,448			1,448			2,057
Total Liabilities	[14]	10,607			10,607			13,074
Total MTM Derivative Contract Net Assets (Liabilities)	[14]	31,272			31,272			15,609
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	[14]	16,514			16,514			22,328
Long-term Risk Management Assets	[14]	2,026			2,026			3,317
Total Assets	[14]	18,540			18,540			25,645
Current Risk Management Liabilities	[14]	4,493			4,493			5,223
Long-term Risk Management Liabilities	[14]	982			982			1,395
Total Liabilities	[14]	5,475			5,475			6,618
Total MTM Derivative Contract Net Assets (Liabilities)	[14]	13,065			13,065			19,027
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	[14]	0			0			7,242
Long-term Risk Management Assets	[14]	44,056			44,056			45,102
Total Assets	[14]	44,056			44,056			52,344
Current Risk Management Liabilities	[14]	2,010			2,010			1,943
Long-term Risk Management Liabilities	[14]	4,573			4,573			3,013
Total Liabilities	[14]	6,583			6,583			4,956
Total MTM Derivative Contract Net Assets (Liabilities)	[14]	37,473			37,473			47,388
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	[14]	1,731			1,731			0
Long-term Risk Management Assets	[14]	29			29			0
Total Assets	[14]	1,760			1,760			0
Current Risk Management Liabilities	[14]	129			129			918
Long-term Risk Management Liabilities	[14]	0			0			0
Total Liabilities	[14]	129			129			918
Total MTM Derivative Contract Net Assets (Liabilities)	[14]	1,631			1,631			(918)
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	[14]	2,077			2,077			31
Long-term Risk Management Assets	[14]	33			33			0
Total Assets	[14]	2,110			2,110			31
Current Risk Management Liabilities	[14]	2,523			2,523			1,082
Long-term Risk Management Liabilities	[14]	0			0			0
Total Liabilities	[14]	2,523			2,523			1,082
Total MTM Derivative Contract Net Assets (Liabilities)	[14]	$ (413)			$ (413)			$ (1,051)
Power [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		440,000			440,000			334,000
Power [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		82,828			82,828			32,479
Power [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		38,036			38,036			23,774
Power [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		5,428			5,428			20,334
Power [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		26,530			26,530			16,765
Power [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MWh		31,839			31,839			20,469
Coal [Member]
Commodity:
Derivative, Mass Notional Amount | T		2,000			2,000			3,000
Coal [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		232			232			279
Coal [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		250			250			500
Coal [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Mass Notional Amount | T		0			0			0
Coal [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Mass Notional Amount | T		750			750			1,500
Natural Gas [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		73,000			73,000			106,000
Natural Gas [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		339			339			421
Natural Gas [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		227			227			286
Natural Gas [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		0			0			0
Natural Gas [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		12			12			0
Natural Gas [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Energy Notional Amount | MMBTU		14			14			0
Heating Oil and Gasoline [Member]
Commodity:
Derivative, Volume Notional Amount | gal		8,000			8,000			6,000
Heating Oil and Gasoline [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1,468			1,468			1,089
Heating Oil and Gasoline [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		695			695			521
Heating Oil and Gasoline [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		1,546			1,546			1,108
Heating Oil and Gasoline [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Volume Notional Amount | gal		852			852			614
Heating Oil and Gasoline [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Volume Notional Amount | gal		975			975			699
Interest Rate Contract [Member]
Commodity:
Derivative, Notional Amount		$ 129,000			$ 129,000			$ 152,000
Interest Rate Contract [Member] | Appalachian Power Co [Member]
Commodity:
Derivative, Notional Amount		3,590			3,590			5,094
Interest Rate Contract [Member] | Indiana Michigan Power Co [Member]
Commodity:
Derivative, Notional Amount		2,435			2,435			3,455
Interest Rate Contract [Member] | Ohio Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Public Service Co Of Oklahoma [Member]
Commodity:
Derivative, Notional Amount		0			0			0
Interest Rate Contract [Member] | Southwestern Electric Power Co [Member]
Commodity:
Derivative, Notional Amount		0			0			$ 0
Vertically Integrated Utilities Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		1,000		4,000	7,000		22,000
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		480		1,184	1,158		6,031
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		619		1,323	3,241		7,479
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		35		56	35		56
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		35		63	24		127
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		43		(79)	26		(56)
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		355		0	355		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		1,005		(300)	1,005		(521)
Sales to AEP Affiliates [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Sales to AEP Affiliates [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		300	0		521
Sales to AEP Affiliates [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	0		0
Other Operation Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	(2,000)		0
Other Operation Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(80)			(199)
Other Operation Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(58)			(158)
Other Operation Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(111)			(261)
Other Operation Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(76)			(198)
Other Operation Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(99)			(246)
Maintenance Expense [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	(1,000)		0
Maintenance Expense [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(133)			(338)
Maintenance Expense [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(55)			(135)
Maintenance Expense [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(114)			(257)
Maintenance Expense [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(79)			(160)
Maintenance Expense [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		(84)			(177)
Purchased Electricity for Resale [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0		0	4,000		0
Purchased Electricity for Resale [Member] | Appalachian Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		11			740
Purchased Electricity for Resale [Member] | Indiana Michigan Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		38			332
Purchased Electricity for Resale [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0			0
Purchased Electricity for Resale [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0			0
Purchased Electricity for Resale [Member] | Southwestern Electric Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		0			0
Other Revenues [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts		10,000		16,000	59,000		48,000
Regulatory Assets [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[15]	4,000		0	0		0
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	[16]	558		0	1,275		4
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	[16]	328		0	(232)		0
Regulatory Assets [Member] | Ohio Power Co [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[16]	0		0	0		0
Regulatory Assets [Member] | Public Service Co Of Oklahoma [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[16]	954		(12)	805		(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	[16]	2,111		(16)	(1,422)		(13)
Regulatory Liabilities [Member]
Amount of Gain (Loss) Recognized on Risk Management Contracts
Amount of Gain (Loss) Recognized on Risk Management Contracts	[15]	49,000		29,000	53,000		118,000
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	[16]	26,809		13,718	28,600		46,050
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	[16]	8,415		8,793	5,839		27,110
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	[16]	(7,272)		6,404	(2,599)		41,503
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	[16]	6,242		(669)	5,575		(189)
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	[16]	9,350		$ (1,019)	13,309		$ 311
Risk Management Assets [Member] | Appalachian Power Co [Member]
Affiliated Derivative Transactions
Affiliated Transactions Related To Standard Service Offer Auctions		2,690			2,690
Risk Management Assets [Member] | Indiana Michigan Power Co [Member]
Affiliated Derivative Transactions
Affiliated Transactions Related To Standard Service Offer Auctions		3,137			3,137
Regulatory Liabilities and Deferred Investment Tax Credits [Member] | Appalachian Power Co [Member]
Affiliated Derivative Transactions
Affiliated Transactions Related To Standard Service Offer Auctions		2,690			2,690
Regulatory Liabilities and Deferred Investment Tax Credits [Member] | Indiana Michigan Power Co [Member]
Affiliated Derivative Transactions
Affiliated Transactions Related To Standard Service Offer Auctions		$ 3,137			$ 3,137
[1]	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
[2]	Represents the amount of collateral AEP subsidiaries would have been required to post for other significant non-derivative contracts including AGR jointly owned plant contracts and various other commodity related contracts.
[3]	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.''
[4]	The June 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($5) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $16 million in 2015, $53 million in periods 2016-2018, $8 million in periods 2019-2020 and $3 million in periods 2021-2032; Level 3 matures $33 million in 2015, $59 million in periods 2016-2018, $22 million in periods 2019-2020 and $93 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts.
[5]	The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts.
[6]	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.”
[7]	Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
[8]	Hedging Assets and Hedging Liabilities are included in Risk Management Assets and Liabilities on the condensed balance sheets.
[9]	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."
[10]	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."
[11]	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.
[12]	Amounts include counterparty netting of risk management and hedging contracts and associated cash collateral in accordance with the accounting guidance for "Derivatives and Hedging."
[13]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[14]	There are no derivative contracts subject to a master netting arrangement or similar agreement which are not offset in the statement of financial position.
[15]	Represents realized and unrealized gains and losses subject to regulatory accounting treatment recorded as either current or noncurrent on the condensed balance sheets.
[16]	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 Long-term Debt, Othe

Fair Value Long-term Debt, Other Temporary Investments, Nuclear Trusts (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		$ 19,578,000		$ 19,578,000		$ 18,684,000
Long Term Debt, Fair Value		21,205,000		21,205,000		21,075,000
Other Temporary Investments
Cost		343,000		343,000		374,000
Gross Unrealized Gains		13,000		13,000		12,000
Gross Unrealized Losses		0		0		0
Estimated Fair Value		356,000		356,000		386,000
Debt and Equity Securities Within Other Temporary Investments [Abstract]
Proceeds from Investment Sales		0	$ 0	0	$ 0
Purchases of Investments		0	0	0	1,000
Gross Realized Gains on Investment Sales		0	0	0	0
Gross Realized Losses on Investment Sales		0	0	0	0
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		2,106,000		2,106,000		2,096,000
Gross Unrealized Gains		636,000		636,000		649,000
Other-Than-Temporary Impairments		(82,000)		(82,000)		(85,000)
Securities Activity Within Decommissioning and SNF Trusts [Abstract]
Proceeds from Investment Sales		288,000	335,000	516,000	483,000
Purchases of Investments		295,000	345,000	541,000	509,000
Gross Realized Gains on Investment Sales		8,000	9,000	19,000	17,000
Gross Realized Losses on Investment Sales		6,000	8,000	10,000	9,000
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,106,000		2,106,000		2,096,000
Fair Value Measurements (Textuals) [Abstract]
Adjusted Cost of Debt Securities		877,000		877,000		903,000
Adjusted Cost of Domestic Equity Securities		540,000		540,000		524,000
Appalachian Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		3,966,647		3,966,647		3,980,274
Long Term Debt, Fair Value		4,396,429		4,396,429		4,711,210
Indiana Michigan Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,088,913		2,088,913		2,027,397
Long Term Debt, Fair Value		2,264,196		2,264,196		2,255,124
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		2,106,090		2,106,090		2,095,732
Gross Unrealized Gains		635,770		635,770		649,132
Other-Than-Temporary Impairments		(82,358)		(82,358)		(85,495)
Securities Activity Within Decommissioning and SNF Trusts [Abstract]
Proceeds from Investment Sales		287,620	334,834	515,784	482,534
Purchases of Investments		294,870	344,324	540,711	508,835
Gross Realized Gains on Investment Sales		7,657	9,077	18,810	17,218
Gross Realized Losses on Investment Sales		5,885	$ 7,834	9,656	$ 8,708
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		2,106,090		2,106,090		2,095,732
Fair Value Measurements (Textuals) [Abstract]
Adjusted Cost of Debt Securities		877,000		877,000		903,000
Adjusted Cost of Domestic Equity Securities		540,000		540,000		524,000
Ohio Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,189,159		2,189,159		2,297,123
Long Term Debt, Fair Value		2,515,960		2,515,960		2,709,452
Public Service Co Of Oklahoma [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		1,290,995		1,290,995		1,041,036
Long Term Debt, Fair Value		1,417,359		1,417,359		1,216,205
Southwestern Electric Power Co [Member]
Book Values and Fair Values of Long - term Debt
Total Long-term Debt Outstanding		2,435,478		2,435,478		2,140,437
Long Term Debt, Fair Value		2,600,476		2,600,476		2,402,639
Cash [Member]
Other Temporary Investments
Cost	[1]	249,000		249,000		280,000
Gross Unrealized Gains	[1]	0		0		0
Gross Unrealized Losses	[1]	0		0		0
Estimated Fair Value	[1],[2]	249,000		249,000		280,000
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value	[3]	53,000		53,000		20,000
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[3]	53,000		53,000		20,000
Cash [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value	[4]	52,861		52,861		19,966
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[4]	52,861		52,861		19,966
Fixed Income Funds [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		918,000		918,000		953,000
Gross Unrealized Gains		41,000		41,000		50,000
Other-Than-Temporary Impairments		(4,000)		(4,000)		(6,000)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		918,000		918,000		953,000
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		918,046		918,046		953,387
Gross Unrealized Gains		41,161		41,161		50,344
Other-Than-Temporary Impairments		(4,102)		(4,102)		(6,353)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		918,046		918,046		953,387
Mutual Funds Fixed Income [Member]
Other Temporary Investments
Cost		81,000		81,000		81,000
Gross Unrealized Gains		0		0		0
Gross Unrealized Losses		0		0		0
Estimated Fair Value		81,000		81,000		81,000
Domestic [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value	[5]	1,135,000		1,135,000		1,123,000
Gross Unrealized Gains		595,000		595,000		599,000
Other-Than-Temporary Impairments		(78,000)		(78,000)		(79,000)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[5]	1,135,000		1,135,000		1,123,000
Domestic [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value	[6]	1,135,183		1,135,183		1,122,379
Gross Unrealized Gains		594,609		594,609		598,788
Other-Than-Temporary Impairments		(78,256)		(78,256)		(79,142)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities	[6]	1,135,183		1,135,183		1,122,379
Mutual Funds Equity [Member]
Other Temporary Investments
Cost		13,000		13,000		13,000
Gross Unrealized Gains		13,000		13,000		12,000
Gross Unrealized Losses		0		0		0
Estimated Fair Value	[5]	26,000		26,000		25,000
Cash and Cash Equivalents [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		53,000		53,000		20,000
Gross Unrealized Gains		0		0		0
Other-Than-Temporary Impairments		0		0		0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		53,000		53,000		20,000
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		52,861		52,861		19,966
Gross Unrealized Gains		0		0		0
Other-Than-Temporary Impairments		0		0		0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		52,861		52,861		19,966
US Government Agencies Debt Securities [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		786,000		786,000		697,000
Gross Unrealized Gains		37,000		37,000		45,000
Other-Than-Temporary Impairments		(3,000)		(3,000)		(5,000)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		786,000		786,000		697,000
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		786,222		786,222		697,042
Gross Unrealized Gains		37,318		37,318		44,615
Other-Than-Temporary Impairments		(2,613)		(2,613)		(5,016)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		786,222		786,222		697,042
Corporate Debt [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		62,000		62,000		48,000
Gross Unrealized Gains		3,000		3,000		4,000
Other-Than-Temporary Impairments		(1,000)		(1,000)		(1,000)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		62,000		62,000		48,000
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		61,654		61,654		47,792
Gross Unrealized Gains		2,851		2,851		4,523
Other-Than-Temporary Impairments		(1,115)		(1,115)		(1,018)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		61,654		61,654		47,792
State and Local Jurisdiction [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		70,000		70,000		208,000
Gross Unrealized Gains		1,000		1,000		1,000
Other-Than-Temporary Impairments		0		0		0
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		70,000		70,000		208,000
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		70,170		70,170		208,553
Gross Unrealized Gains		992		992		1,206
Other-Than-Temporary Impairments		(374)		(374)		(319)
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		70,170		70,170		$ 208,553
Within One Year [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		141,000		141,000
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		141,000		141,000
Within One Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		140,990		140,990
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		140,990		140,990
One Year To Five Year [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		376,000		376,000
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		376,000		376,000
One Year To Five Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		375,637		375,637
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		375,637		375,637
Five Year To Ten Year [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		186,000		186,000
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		186,000		186,000
Five Year To Ten Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		186,505		186,505
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		186,505		186,505
After Ten Year [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		215,000		215,000
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		215,000		215,000
After Ten Year [Member] | Indiana Michigan Power Co [Member]
Nuclear Trust Fund Investments [Abstract]
Estimated Fair Value		214,914		214,914
Contractual Maturities, Fair Value of Debt Securities
Contractual Maturities, Fair Value of Debt Securities		$ 214,914		$ 214,914
[1]	Primarily represents amounts held for the repayment of debt.
[2]	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.
[3]	Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[4]	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[5]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[6]	Amounts represent publicly traded equity securities and equity-based mutual funds.

Fair Value Assets and Liabiliti

Fair Value Assets and Liabilities (Details) $ in Thousands		3 Months Ended			6 Months Ended			12 Months Ended
		Jun. 30, 2015USD ($)$ / MWh		Jun. 30, 2014USD ($)	Jun. 30, 2015USD ($)$ / MWh		Jun. 30, 2014USD ($)	Dec. 31, 2014USD ($)$ / MWh
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	$ 195,000			$ 195,000			$ 163,000
Other Temporary Investments		356,000			356,000			386,000
Risk Management Assets
Risk Management Assets		535,000			535,000			472,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		2,106,000			2,106,000			2,096,000
Total Assets		3,192,000			3,192,000			3,117,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		252,000			252,000			223,000
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		131,000		$ 105,000	151,000		$ 117,000	117,000
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[2],[3]	2,000		(14,000)	12,000		82,000
Unrealized Gain (Loss) Included in Net Income (or Changes in Net Assets) Relating to Assets Still Held at the Reporting Date	[2]	12,000			51,000		(9,000)
Realized and Unrealized Gains (Losses) Included in Other Comprehensive Income				6,000	(2,000)		14,000
Purchases, Issuances and Settlements	[4]	(16,000)		(2,000)	(54,000)		(102,000)
Transfers into Level 3	[5],[6]	42,000		5,000	21,000		1,000
Transfers out of Level 3	[6],[7]	(2,000)		(6,000)	(14,000)		(7,000)
Changes in Fair Value Allocated to Regulated Jurisdictions	[8]	34,000		38,000	38,000		36,000
Ending Balance		203,000		132,000	$ 203,000		132,000	$ 151,000
Level 3 Quantitative Information [Abstract]
Counterparty Credit Risk	[9]				3.28%			3.03%
Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	17,000			$ 17,000			$ 17,000
Other Temporary Investments		312,000			312,000			340,000
Risk Management Assets
Risk Management Assets		23,000			23,000			37,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,177,000			1,177,000			1,132,000
Total Assets		1,529,000			1,529,000			1,526,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		38,000			38,000			65,000
Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	6,000			6,000			1,000
Other Temporary Investments		7,000			7,000			9,000
Risk Management Assets
Risk Management Assets		548,000			548,000			561,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		918,000			918,000			953,000
Total Assets		1,479,000			1,479,000			1,524,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		477,000			477,000			467,000
Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	0			0			0
Other Temporary Investments		0			0			0
Risk Management Assets
Risk Management Assets		270,000			270,000			190,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Total Assets		270,000			270,000			190,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		67,000			67,000			39,000
Fair Value Inputs Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[1]	172,000			172,000			145,000
Other Temporary Investments		37,000			37,000			37,000
Risk Management Assets
Risk Management Assets		(306,000)			(306,000)			(316,000)
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		11,000			11,000			11,000
Total Assets		(86,000)			(86,000)			(123,000)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		(330,000)			(330,000)			(348,000)
2015 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(5,000)			(5,000)			(18,000)
2015 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		16,000			16,000			31,000
2015 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		33,000			33,000			50,000
2016 - 2018 [Member] | Level 1 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		(10,000)			(10,000)			(10,000)
2016 - 2018 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		53,000			53,000			52,000
2016 - 2018 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		59,000			59,000			29,000
2019 - 2020 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		8,000			8,000			12,000
2019 - 2020 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		22,000			22,000			9,000
2021 - 2032 [Member] | Level 2 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		3,000			3,000			1,000
2021 - 2032 [Member] | Level 3 [Member]
Fair Value Measurements 1 (Textuals) [Abstract]
Maturity of Net Fair Value of Risk Management Contracts Prior to Cash Collateral, Assets/Liabilities		93,000			93,000			66,000
Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[10]	523,000	[11]		523,000	[11]		453,000	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	227,000	[11]		227,000	[11]		199,000	[12]
Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10]	23,000	[11]		23,000	[11]		37,000	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	38,000	[11]		38,000	[11]		65,000	[12]
Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10]	524,000	[11]		524,000	[11]		528,000	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	444,000	[11]		444,000	[11]		432,000	[12]
Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10]	269,000	[11]		269,000	[11]		190,000	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	62,000	[11]		62,000	[11]		36,000	[12]
Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member]
Risk Management Assets
Risk Management Assets	[10]	(293,000)	[11]		(293,000)	[11]		(302,000)	[12]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	(317,000)	[11]		(317,000)	[11]		(334,000)	[12]
Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		232,000			232,000			157,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 65,000			$ 65,000			$ 37,000
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	13.5			13.5			11.37
Forward Price Range High | $ / MWh	[13]	163.52			163.52			159.92
Weighted Average Market Price | $ / MWh	[13]	37.79			37.79			57.18
FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 38,000			$ 38,000			$ 33,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 2,000			$ 2,000			$ 2,000
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[13]	(8)			(8)			(14.63)
Forward Price Range High | $ / MWh	[13]	9.87			9.87			20.02
Weighted Average Market Price | $ / MWh	[13]	1.37			1.37			0.96
Commodity Hedges [Member]
Risk Management Assets
Risk Management Assets	[10]	$ 10,000			$ 10,000			$ 16,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	19,000			19,000			14,000
Commodity Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[10]	0			0			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	0			0			0
Commodity Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[10]	24,000			24,000			32,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	29,000			29,000			27,000
Commodity Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[10]	1,000			1,000			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	5,000			5,000			3,000
Commodity Hedges [Member] | Fair Value Inputs Other [Member]
Risk Management Assets
Risk Management Assets	[10]	(15,000)			(15,000)			(16,000)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[10]	(15,000)			(15,000)			(16,000)
Interest Rate Foreign Currency Hedges [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		1,000			1,000			1,000
Interest Rate Foreign Currency Hedges [Member] | Level 1 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0			0			0
Interest Rate Foreign Currency Hedges [Member] | Level 2 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		1,000			1,000			1,000
Interest Rate Foreign Currency Hedges [Member] | Level 3 [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0			0			0
Interest Rate Foreign Currency Hedges [Member] | Fair Value Inputs Other [Member]
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0			0			0
Fair Value Hedges [Member]
Risk Management Assets
Risk Management Assets		2,000			2,000			3,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		5,000			5,000			9,000
Fair Value Hedges [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets		0			0			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0			0			0
Fair Value Hedges [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets		0			0			1,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		3,000			3,000			7,000
Fair Value Hedges [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		0			0			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		0			0			0
Fair Value Hedges [Member] | Fair Value Inputs Other [Member]
Risk Management Assets
Risk Management Assets		2,000			2,000			2,000
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		2,000			2,000			2,000
Appalachian Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	15,583			15,583			15,632
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		57,462			57,462			44,315
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		5,987		7,401	15,742		10,562	10,562
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[15],[16]	(1,380)		(4,046)	1,230		29,132
Purchases, Issuances and Settlements	[17]	(1,606)		(32)	(14,964)		(31,790)
Transfers into Level 3	[18],[19]			182			(3,643)
Transfers out of Level 3	[19],[20]	1,167		3	1,167		(2)
Changes in Fair Value Allocated to Regulated Jurisdictions	[21]	29,668		14,886	30,661		14,135
Ending Balance		33,836		18,394	33,836		18,394	15,742
Appalachian Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	15,565			15,565			15,599
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		15,741			15,741			15,805
Appalachian Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		20,754			20,754			20,197
Appalachian Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	0			0			0
Risk Management Assets
Risk Management Assets		34,210			34,210			17,654
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		34,210			34,210			17,654
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		374			374			1,912
Appalachian Power Co [Member] | Fair Value Inputs Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	18			18			33
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		(13,243)			(13,243)			(9,341)
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	41,879			41,879			28,683
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	10,607			10,607			13,074
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	176			176			206
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	197			197			227
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	20,754			20,754			20,197
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	24,212			24,212			20,339
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	34,210			34,210			17,654
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	374			374			1,912
Appalachian Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	(13,261)			(13,261)			(9,374)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	(14,176)			(14,176)			(9,404)
Appalachian Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		10,570			10,570			5,801
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 183			$ 183			$ 1,799
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[24]	15.36			15.36			13.43
Forward Price Range High | $ / MWh	[24]	56.3			56.3			123.02
Weighted Average Market Price | $ / MWh	[24]	35.88			35.88			52.47
Appalachian Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 23,640			$ 23,640			$ 11,853
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 191			$ 191			$ 113
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[24]	(6.16)			(6.16)			(14.63)
Forward Price Range High | $ / MWh	[24]	9.87			9.87			20.02
Weighted Average Market Price | $ / MWh	[24]	1.57			1.57			1.01
Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		$ 2,106,090			$ 2,106,090			$ 2,095,732
Total Assets		2,124,630			2,124,630			2,121,377
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		5,573		4,842	14,704		7,164	7,164
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[15],[16]	(802)		(2,554)	(825)		18,211
Purchases, Issuances and Settlements	[17]	(2,264)		(35)	(11,319)		(20,014)
Transfers into Level 3	[18],[19]			124			(2,471)
Transfers out of Level 3	[19],[20]	792		2	792		(2)
Changes in Fair Value Allocated to Regulated Jurisdictions	[21]	8,545		10,544	8,492		10,035
Ending Balance		11,844		12,923	11,844		12,923	14,704
Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		1,177,001			1,177,001			1,131,797
Total Assets		1,177,120			1,177,120			1,131,937
Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		918,046			918,046			953,387
Total Assets		933,474			933,474			969,280
Indiana Michigan Power Co [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		12,710			12,710			16,008
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Total Assets		12,710			12,710			16,008
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		866			866			1,304
Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		11,043			11,043			10,548
Total Assets		1,326			1,326			4,152
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	18,540			18,540			25,645
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	5,475			5,475			6,618
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	119			119			140
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	133			133			154
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	15,428			15,428			15,893
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	14,621			14,621			11,440
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	12,710			12,710			16,008
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	866			866			1,304
Indiana Michigan Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	(9,717)			(9,717)			(6,396)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	(10,145)			(10,145)			(6,280)
Indiana Michigan Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		9,184			9,184			6,375
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 116			$ 116			$ 1,219
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[24]	15.36			15.36			13.43
Forward Price Range High | $ / MWh	[24]	56.3			56.3			123.02
Weighted Average Market Price | $ / MWh	[24]	35.88			35.88			52.47
Indiana Michigan Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		$ 3,526			$ 3,526			$ 9,633
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 750			$ 750			$ 85
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[24]	(6.16)			(6.16)			(14.63)
Forward Price Range High | $ / MWh	[24]	9.87			9.87			20.02
Weighted Average Market Price | $ / MWh	[24]	1.57			1.57			1.01
Ohio Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]							$ 28,696
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets								81,040
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		$ 45,942		3,912	$ 48,402		2,920	2,920
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[15],[16]	638		(4,236)	1,548		30,768
Purchases, Issuances and Settlements	[17]	(1,691)		347	(8,368)		(33,688)
Transfers into Level 3	[18],[19]			0			0
Transfers out of Level 3	[19],[20]	0		0	0		0
Changes in Fair Value Allocated to Regulated Jurisdictions	[21]	(7,232)		9,277	(3,925)		9,300
Ending Balance		37,657		9,300	37,657		9,300	48,402
Ohio Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]							408
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets								408
Ohio Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]							0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets								0
Ohio Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]							0
Risk Management Assets
Risk Management Assets								52,343
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets								52,343
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities								3,941
Ohio Power Co [Member] | Fair Value Inputs Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]							28,288
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets								28,289
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	44,056			44,056			52,344
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	6,583			6,583			4,956
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	0			0			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	0			0			0
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	121			121			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	426			426			1,116
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	42,474			42,474			52,343
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	4,817			4,817			3,941
Ohio Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	1,461			1,461			1
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	1,340			1,340			(101)
Ohio Power Co [Member] | Energy Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		42,474			42,474			45,101
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 4,817			$ 4,817			$ 3,941
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[24]	42.89			42.89			48.25
Forward Price Range High | $ / MWh	[24]	163.52			163.52			159.92
Weighted Average Market Price | $ / MWh	[24]	91.51			91.51			84.04
Ohio Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets								$ 7,242
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities								$ 0
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[24]							(14.63)
Forward Price Range High | $ / MWh	[24]							20.02
Weighted Average Market Price | $ / MWh	[24]							1.01
Public Service Co Of Oklahoma [Member]
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		$ (685)		349	$ (377)		0	$ 0
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[15],[16]	766		(349)	(176)		0
Purchases, Issuances and Settlements	[17]	(81)		0	553		0
Transfers into Level 3	[18],[19]			0			0
Transfers out of Level 3	[19],[20]	0		0	0		0
Changes in Fair Value Allocated to Regulated Jurisdictions	[21]	1,699		(3)	1,699		(3)
Ending Balance		1,699		(3)	1,699		(3)	(377)
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	1,760			1,760			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	129			129			918
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	2			2			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	5			5			0
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	98			98			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	278			278			595
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	1,750			1,750			360
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	51			51			737
Public Service Co Of Oklahoma [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	(90)			(90)			(360)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	(205)			(205)			(414)
Public Service Co Of Oklahoma [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		1,750			1,750			360
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 51			$ 51			$ 737
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[24]	(6.16)			(6.16)			(14.63)
Forward Price Range High | $ / MWh	[24]	9.87			9.87			20.02
Weighted Average Market Price | $ / MWh	[24]	1.57			1.57			1.01
Southwestern Electric Power Co [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	$ 8,017			$ 8,017			$ 14,356
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		10,127			10,127			14,387
Changes in the Fair Value of Net Trading Derivatives and other investments
Beginning Balance		(1,222)		442	(460)		0	0
Realized Gain (Loss) Included in Net Income (or Changes in Net Assets)	[15],[16]	4,173		(442)	9,187		0
Purchases, Issuances and Settlements	[17]	(2,951)		0	(8,727)		0
Transfers into Level 3	[18],[19]			0			0
Transfers out of Level 3	[19],[20]	0		0	0		0
Changes in Fair Value Allocated to Regulated Jurisdictions	[21]	2,039		(3)	2,039		(3)
Ending Balance		2,039		$ (3)	2,039		$ (3)	(460)
Southwestern Electric Power Co [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	6,391			6,391			12,660
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		6,394			6,394			12,660
Southwestern Electric Power Co [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		114			114			31
Southwestern Electric Power Co [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		2,100			2,100			439
Southwestern Electric Power Co [Member] | Fair Value Inputs Other [Member]
Assets, Fair Value Disclosure [Abstract]
Cash and Cash Equivalents	[14]	1,626			1,626			1,696
Spent Nuclear Fuel and Decommissioning Trusts
Total Assets		1,519			1,519			1,257
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	2,110			2,110			31
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	2,523			2,523			1,082
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 1 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	3			3			0
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	6			6			0
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 2 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	114			114			31
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	2,697			2,697			684
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	2,100			2,100			439
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	61			61			899
Southwestern Electric Power Co [Member] | Risk Management Commodity Contracts [Member] | Fair Value Inputs Other [Member]
Risk Management Assets
Risk Management Assets	[22],[23]	(107)			(107)			(439)
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities	[22],[23]	(241)			(241)			(501)
Southwestern Electric Power Co [Member] | FTRs [Member] | Level 3 [Member]
Risk Management Assets
Risk Management Assets		2,100			2,100			439
Liabilities, Fair Value Disclosure [Abstract]
Risk Management Liabilities		$ 61			$ 61			$ 899
Level 3 Quantitative Information [Abstract]
Forward Price Range Low | $ / MWh	[24]	(6.16)			(6.16)			(14.63)
Forward Price Range High | $ / MWh	[24]	9.87			9.87			20.02
Weighted Average Market Price | $ / MWh	[24]	1.57			1.57			1.01
Cash [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1],[25]	$ 249,000			$ 249,000			$ 280,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[26]	53,000			53,000			20,000
Cash [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	205,000			205,000			234,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[26]	42,000			42,000			9,000
Cash [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	7,000			7,000			9,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[26]	0			0			0
Cash [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	0			0			0
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[26]	0			0			0
Cash [Member] | Fair Value Inputs Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[1]	37,000			37,000			37,000
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[26]	11,000			11,000			11,000
Cash [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[27]	52,861			52,861			19,966
Cash [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[27]	41,818			41,818			9,418
Cash [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[27]	0			0			0
Cash [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[27]	0			0			0
Cash [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[27]	11,043			11,043			10,548
Fixed Income Funds [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		918,000			918,000			953,000
Fixed Income Funds [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		918,000			918,000			953,000
Fixed Income Funds [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Fair Value Inputs Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		918,046			918,046			953,387
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		918,046			918,046			953,387
Fixed Income Funds [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
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			0
Mutual Funds Fixed Income [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		81,000			81,000			81,000
Mutual Funds Fixed Income [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		81,000			81,000			81,000
Mutual Funds Fixed Income [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0			0			0
Mutual Funds Fixed Income [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0			0			0
Mutual Funds Fixed Income [Member] | Fair Value Inputs Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments		0			0			0
Domestic [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[28]	1,135,000			1,135,000			1,123,000
Domestic [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[28]	1,135,000			1,135,000			1,123,000
Domestic [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[28]	0			0			0
Domestic [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[28]	0			0			0
Domestic [Member] | Fair Value Inputs Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[28]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[29]	1,135,183			1,135,183			1,122,379
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[29]	1,135,183			1,135,183			1,122,379
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[29]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[29]	0			0			0
Domestic [Member] | Indiana Michigan Power Co [Member] | Fair Value Inputs Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts	[29]	0			0			0
Mutual Funds Equity [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[28]	26,000			26,000			25,000
Mutual Funds Equity [Member] | Level 1 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[28]	26,000			26,000			25,000
Mutual Funds Equity [Member] | Level 2 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[28]	0			0			0
Mutual Funds Equity [Member] | Level 3 [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[28]	0			0			0
Mutual Funds Equity [Member] | Fair Value Inputs Other [Member]
Assets, Fair Value Disclosure [Abstract]
Other Temporary Investments	[28]	0			0			0
Cash and Cash Equivalents [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		53,000			53,000			20,000
Cash and Cash Equivalents [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		52,861			52,861			19,966
US Government Agencies Debt Securities [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		786,000			786,000			697,000
US Government Agencies Debt Securities [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		786,000			786,000			697,000
US Government Agencies Debt Securities [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Fair Value Inputs Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		786,222			786,222			697,042
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		786,222			786,222			697,042
US Government Agencies Debt Securities [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
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			0
Corporate Debt [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		62,000			62,000			48,000
Corporate Debt [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		62,000			62,000			48,000
Corporate Debt [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Fair Value Inputs Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		61,654			61,654			47,792
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		61,654			61,654			47,792
Corporate Debt [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
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			0
State and Local Jurisdiction [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		70,000			70,000			208,000
State and Local Jurisdiction [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		70,000			70,000			208,000
State and Local Jurisdiction [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Fair Value Inputs Other [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		70,170			70,170			208,553
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 1 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 2 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		70,170			70,170			208,553
State and Local Jurisdiction [Member] | Indiana Michigan Power Co [Member] | Level 3 [Member]
Spent Nuclear Fuel and Decommissioning Trusts
Spent Nuclear Fuel and Decommissioning Trusts		0			0			0
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			$ 0
[1]	Amounts in ''Other'' column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 and Level 2 amounts primarily represent investments in money market funds.
[2]	Included in revenues on the 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 June 30, 2015 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures ($5) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $16 million in 2015, $53 million in periods 2016-2018, $8 million in periods 2019-2020 and $3 million in periods 2021-2032; Level 3 matures $33 million in 2015, $59 million in periods 2016-2018, $22 million in periods 2019-2020 and $93 million in periods 2021-2032. Risk management commodity contracts are substantially comprised of power contracts.
[12]	The December 31, 2014 maturity of the net fair value of risk management contracts prior to cash collateral, assets/(liabilities), is as follows: Level 1 matures $(18) million in 2015 and ($10) million in periods 2016-2018; Level 2 matures $31 million in 2015, $52 million in periods 2016-2018, $12 million in periods 2019-2020 and $1 million in periods 2021-2030; Level 3 matures $50 million in 2015, $29 million in periods 2016-2018, $9 million in periods 2019-2020 and $66 million in periods 2021-2030. Risk management commodity contracts are substantially comprised of power contracts.
[13]	Represents market prices in dollars per MWh.
[14]	Amounts in "Other" column primarily represent cash deposits in bank accounts with financial institutions or with third parties. Level 1 amounts primarily represent investment in money market funds.
[15]	Included in revenues on the condensed statements of income.
[16]	Represents the change in fair value between the beginning of the reporting period and the settlement of the risk management commodity contract.
[17]	Represents the settlement of risk management commodity contracts for the reporting period.
[18]	Represents existing assets or liabilities that were previously categorized as Level 2.
[19]	Transfers are recognized based on their value at the beginning of the reporting period that the transfer occurred.
[20]	Represents existing assets or liabilities that were previously categorized as Level 3.
[21]	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.
[22]	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.”
[23]	Substantially comprised of power contracts for APCo, I&M and OPCo and coal contracts for PSO and SWEPCo.
[24]	Represents market prices in dollars per MWh.
[25]	Primarily represents amounts held for the repayment of debt.
[26]	Amounts in ''Other'' column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[27]	Amounts in “Other” column primarily represent accrued interest receivables from financial institutions. Level 1 amounts primarily represent investments in money market funds.
[28]	Amounts represent publicly traded equity securities and equity-based mutual funds.
[29]	Amounts represent publicly traded equity securities and equity-based mutual funds.

Income Taxes (Details)

Income Taxes (Details)	6 Months Ended
	Jun. 30, 2015
Income Taxes (Textuals) [Abstract]
Pre-2016 TX Income/Franchise Tax Rate	0.95%
New TX Income/Franchise Tax Rate	0.75%
Anticipated TX Income/Franchise Tax Rate	1.00%
Public Service Co Of Oklahoma [Member]
Income Taxes (Textuals) [Abstract]
Pre-2016 TX Income/Franchise Tax Rate	0.95%
New TX Income/Franchise Tax Rate	0.75%
Anticipated TX Income/Franchise Tax Rate	1.00%
Southwestern Electric Power Co [Member]
Income Taxes (Textuals) [Abstract]
Pre-2016 TX Income/Franchise Tax Rate	0.95%
New TX Income/Franchise Tax Rate	0.75%
Anticipated TX Income/Franchise Tax Rate	1.00%

Financing Activities (Details)

Financing Activities (Details) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended		6 Months Ended
		Jul. 23, 2015	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Long-term Debt
Senior Unsecured Notes			$ 13,628,000		$ 13,628,000		$ 12,647,000
Pollution Control Bonds			1,963,000		1,963,000		1,963,000
Notes Payable			409,000		409,000		357,000
Securitization Bonds			2,200,000		2,200,000		2,380,000
Spent Nuclear Fuel Obligation	[1]		266,000		266,000		266,000
Other Long-term Debt			1,144,000		1,144,000		1,101,000
Fair Value of Interest Rate Hedges			(3,000)		(3,000)		(6,000)
Unamortized Discount, Net			(29,000)		(29,000)		(24,000)
Total Long-term Debt Outstanding			19,578,000		19,578,000		18,684,000
Long-term Debt Due Within One Year			1,817,000		1,817,000		2,503,000
Long-term Debt			17,761,000		17,761,000		16,181,000
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[2]				2,624,000
Retirements and Principal Payments					1,727,000	$ 1,205,000
Short-term Debt:
Securitized Debt for Receivables	[3]		708,000		708,000		744,000
Commercial Paper			397,000		397,000		602,000
Total Short-term Debt			$ 1,105,000		$ 1,105,000		$ 1,346,000
Securitized Debt for Receivables	[4]		0.27%		0.27%		0.22%
Comparative Accounts Receivable Information
Effective Interest Rates on Securitization of Accounts Receivable			0.27%	0.22%	0.27%	0.23%
Net Uncollectible Accounts Receivable Written Off			$ 6,000	$ 7,000	$ 13,000	$ 14,000
Customer Accounts Receivable Managed Portfolio
Accounts Receivable Retained Interest and Pledged as Collateral Less Uncollectible Accounts			977,000		977,000		$ 975,000
Total Principal Outstanding			708,000		708,000		744,000
Delinquent Securitized Accounts Receivable			50,000		50,000		44,000
Bad Debt Reserves Related to Securitization, Sale of Accounts Receivable			19,000		19,000		13,000
Unbilled Receivables Related to Securitization, Sale of Accounts Receivable			363,000		363,000		335,000
Financing Activities (Textuals) [Abstract]
Reacquired Pollution Controls Bonds Held by Trustees			385,000		$ 385,000
Maximum Percentage Debt to Capitalization					67.50%
Total Commitment from Bank Conduits to Finance Receivables			750,000	700,000	$ 750,000	700,000
Trust Fund Assets One Time Fee Obligation for Nuclear Fuel Disposition			$ 309,000		$ 309,000		$ 309,000
Commercial Paper [Member]
Short-term Debt:
Commercial Paper	[4]		0.47%		0.47%		0.59%
AEP Subsidiaries [Member]
Long-term Debt
Long-term Debt Due Within One Year			$ 463,000		$ 463,000		$ 431,000
Long-term Debt			$ 2,114,000		2,114,000		2,260,000
AEP Subsidiaries [Member] | Notes Payable One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 1,000
Interest Rate (Variable)					Variable
Due Date					2,017
AEP Generating Co [Member] | Senior Unsecured Notes One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 4,000
Interest Rate (Percentage)			6.33%		6.33%
Due Date					2,037
AEP Texas Central Co [Member] | Securitization Bonds One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 27,000
Interest Rate (Percentage)			0.88%		0.88%
Due Date					2,017
AEP Texas Central Co [Member] | Securitization Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 78,000
Interest Rate (Percentage)			5.09%		5.09%
Due Date					2,015
AEP Texas Central Co [Member] | Securitization Bonds Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 42,000
Interest Rate (Percentage)			6.25%		6.25%
Due Date					2,016
AEP Texas Central Co [Member] | Securitization Bonds Four [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments		$ 94,000
Appalachian Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 3,966,647		$ 3,966,647		3,980,274
Long-term Debt Due Within One Year			252,410		252,410		552,212
Long-term Debt			3,714,237		3,714,237		3,342,062
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					661,055	$ 500,016
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Utility Money Pool					82,417
Maximum Loans to Utility Money Pool					694,785
Average Borrowings from Utility Money Pool					58,723
Average Loans to Utility Money Pool					133,887
Net Loans (Borrowings) to/from Utility Money Pool			(33,703)		(33,703)
Authorized Short-term Borrowing Limit					$ 600,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.59%	0.33%
Minimum Interest Rate					0.39%	0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool
Average Interest Rate for Funds Borrowed					0.45%	0.26%
Average Interest Rate for Funds Loaned					0.46%	0.29%
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			139,005		$ 139,005		159,823
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1,573	2,037	4,027	$ 4,460
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			$ 330,593	345,963	$ 760,217	783,159
Financing Activities (Textuals) [Abstract]
Maximum Percentage Debt to Capitalization					67.50%
Appalachian Power Co [Member] | Securitization Bonds One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 11,037
Interest Rate (Percentage)			2.008%		2.008%
Due Date					2,024
Appalachian Power Co [Member] | Notes Payable Affiliated [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 86,000
Interest Rate (Percentage)			3.125%		3.125%
Due Date					2,015
Appalachian Power Co [Member] | Pollution Control Bonds One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 86,000
Interest Rate (Percentage)			1.90%		1.90%
Due Date					2,019
Appalachian Power Co [Member] | Senior Unsecured Notes One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 350,000
Interest Rate (Percentage)			4.45%		4.45%
Due Date					2,045
Appalachian Power Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 300,000
Interest Rate (Percentage)			3.40%		3.40%
Due Date					2,025
Appalachian Power Co [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 350,000
Interest Rate (Percentage)			7.95%		7.95%
Due Date					2,020
Appalachian Power Co [Member] | Senior Unsecured Notes Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 300,000
Interest Rate (Percentage)			3.40%		3.40%
Due Date					2,015
Appalachian Power Co [Member] | Land Note [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 18
Interest Rate (Percentage)			13.718%		13.718%
Due Date					2,026
Indiana Michigan Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,088,913		$ 2,088,913		2,027,397
Long-term Debt Due Within One Year			312,370		312,370		382,187
Long-term Debt			1,776,543		1,776,543		1,645,210
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					150,077	$ 160,292
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Utility Money Pool					200,032
Maximum Loans to Utility Money Pool					13,515
Average Borrowings from Utility Money Pool					141,520
Average Loans to Utility Money Pool					13,501
Net Loans (Borrowings) to/from Utility Money Pool			(127,154)		(127,154)
Authorized Short-term Borrowing Limit					$ 500,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.59%	0.33%
Minimum Interest Rate					0.39%	0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool
Average Interest Rate for Funds Borrowed					0.47%	0.26%
Average Interest Rate for Funds Loaned					0.47%	0.30%
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			145,633		$ 145,633		137,459
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			2,063	1,785	4,420	$ 3,825
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			371,058	353,030	790,619	760,180
Financing Activities (Textuals) [Abstract]
Reacquired Pollution Controls Bonds Held by Trustees			$ 40,000		$ 40,000
Maximum Percentage Debt to Capitalization					67.50%
Indiana Michigan Power Co [Member] | Notes Payable One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 111,300
Interest Rate (Variable)					Variable
Due Date					2,019
Indiana Michigan Power Co [Member] | Notes Payable Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 18,600
Interest Rate (Variable)					Variable
Due Date					2,016
Indiana Michigan Power Co [Member] | Notes Payable Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 13,659
Interest Rate (Variable)					Variable
Due Date					2,017
Indiana Michigan Power Co [Member] | Notes Payable Four [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 16,501
Interest Rate (Variable)					Variable
Due Date					2,019
Indiana Michigan Power Co [Member] | Notes Payable Five [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 5,834
Interest Rate (Variable)					Variable
Due Date					2,019
Indiana Michigan Power Co [Member] | Notes Payable Six [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 844
Interest Rate (Variable)					Variable
Due Date					2,016
Indiana Michigan Power Co [Member] | Notes Payable Seven [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 585
Interest Rate (Percentage)			2.12%		2.12%
Due Date					2,016
Indiana Michigan Power Co [Member] | Other Long Term Debt One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 100,000
Interest Rate (Variable)					Variable
Due Date					2,018
Indiana Michigan Power Co [Member] | Other Long Term Debt Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 93,500
Interest Rate (Variable)					Variable
Due Date					2,015
Indiana Michigan Power Co [Member] | Other Long Term Debt Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 554
Interest Rate (Percentage)			6.00%		6.00%
Due Date					2,025
Ohio Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,189,159		$ 2,189,159		2,297,123
Long-term Debt Due Within One Year			396,045		396,045		131,497
Long-term Debt			1,793,114		1,793,114		2,165,626
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					108,238	$ 364,498
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Utility Money Pool					0
Maximum Loans to Utility Money Pool					367,472
Average Borrowings from Utility Money Pool					0
Average Loans to Utility Money Pool					273,487
Net Loans (Borrowings) to/from Utility Money Pool			187,812		187,812
Authorized Short-term Borrowing Limit					$ 400,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.59%	0.33%
Minimum Interest Rate					0.39%	0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool
Average Interest Rate for Funds Borrowed					0.00%	0.27%
Average Interest Rate for Funds Loaned					0.47%	0.29%
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			366,098		$ 366,098		365,834
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			6,668	6,647	14,683	$ 14,145
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			563,381	626,025	1,278,365	1,312,652
Financing Activities (Textuals) [Abstract]
Reacquired Pollution Controls Bonds Held by Trustees			$ 345,000		345,000
Ohio Power Co [Member] | Securitization Bonds One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 22,200
Interest Rate (Percentage)			0.958%		0.958%
Due Date					2,018
Ohio Power Co [Member] | Securitization Bonds Two [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments		23,000
Ohio Power Co [Member] | Pollution Control Bonds One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 86,000
Interest Rate (Percentage)			3.125%		3.125%
Due Date					2,015
Ohio Power Co [Member] | Other Long Term Debt One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 38
Interest Rate (Percentage)			1.149%		1.149%
Due Date					2,028
Public Service Co Of Oklahoma [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 1,290,995		$ 1,290,995		1,041,036
Long-term Debt Due Within One Year			434		434		427
Long-term Debt			1,290,561		1,290,561		1,040,609
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					212	$ 33,906
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Utility Money Pool					165,947
Maximum Loans to Utility Money Pool					95,472
Average Borrowings from Utility Money Pool					113,117
Average Loans to Utility Money Pool					51,855
Net Loans (Borrowings) to/from Utility Money Pool			64,212		64,212
Authorized Short-term Borrowing Limit					$ 300,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.59%	0.33%
Minimum Interest Rate					0.39%	0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool
Average Interest Rate for Funds Borrowed					0.49%	0.28%
Average Interest Rate for Funds Loaned					0.47%	0.00%
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			131,940		$ 131,940		112,905
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1,324	1,349	2,746	$ 2,672
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			$ 311,885	325,536	$ 614,386	615,753
Financing Activities (Textuals) [Abstract]
Maximum Percentage Debt to Capitalization					67.50%
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 125,000
Interest Rate (Percentage)			3.17%		3.17%
Due Date					2,025
Public Service Co Of Oklahoma [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 125,000
Interest Rate (Percentage)			4.09%		4.09%
Due Date					2,045
Public Service Co Of Oklahoma [Member] | Other Long Term Debt One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 212
Interest Rate (Percentage)			3.00%		3.00%
Due Date					2,027
Southwestern Electric Power Co [Member]
Long-term Debt
Total Long-term Debt Outstanding			$ 2,435,478		$ 2,435,478		2,140,437
Long-term Debt Due Within One Year			153,250		153,250		306,750
Long-term Debt			2,282,228		2,282,228		1,833,687
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					155,125	$ 1,625
Utility Money Pool Participants' Money Pool Activity and Authorized Borrowing Limits
Maximum Borrowings from Utility Money Pool					112,481
Maximum Loans to Utility Money Pool					299,932
Average Borrowings from Utility Money Pool					52,596
Average Loans to Utility Money Pool					170,502
Net Loans (Borrowings) to/from Utility Money Pool			179,709		179,709
Authorized Short-term Borrowing Limit					$ 350,000
Maximum and Minimum Interest Rates
Maximum Interest Rate					0.59%	0.33%
Minimum Interest Rate					0.39%	0.24%
Average Interest Rates for Funds Borrowed from and Loaned to Utility Money Pool
Average Interest Rate for Funds Borrowed					0.46%	0.28%
Average Interest Rate for Funds Loaned					0.49%	0.00%
Accounts Receivable and Accrued Unbilled Revenues
Accounts Receivable and Accrued Unbilled Revenues			163,994		$ 163,994		$ 148,668
Fees Paid to AEP Credit for Customer Accounts Receivable Sold
Fees Paid to AEP Credit for Customer Accounts Receivable Sold			1,625	1,579	3,347	$ 3,145
Proceeds from Sale of Receivables
Proceeds from Sale of Receivables to AEP Credit			$ 381,100	$ 420,909	$ 754,267	$ 811,497
Financing Activities (Textuals) [Abstract]
Maximum Percentage Debt to Capitalization					67.50%
Southwestern Electric Power Co [Member] | Notes Payable One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 1,625
Interest Rate (Percentage)			4.58%		4.58%
Due Date					2,032
Southwestern Electric Power Co [Member] | Pollution Control Bonds One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 53,500
Interest Rate (Percentage)			1.60%		1.60%
Due Date					2,019
Southwestern Electric Power Co [Member] | Pollution Control Bonds Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 53,500
Interest Rate (Percentage)			3.25%		3.25%
Due Date					2,015
Southwestern Electric Power Co [Member] | Senior Unsecured Notes One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances	[5]				$ 400,000
Interest Rate (Percentage)			3.90%		3.90%
Due Date					2,045
Southwestern Electric Power Co [Member] | Senior Unsecured Notes Two [Member] | Subsequent Event [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments		$ 150,000
Interest Rate (Percentage)		4.90%
Due Date		2,015
Southwestern Electric Power Co [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 100,000
Interest Rate (Percentage)			5.375%		5.375%
Due Date					2,015
AEP Transmission Company, LLC [Member] | Senior Unsecured Notes One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 60,000
Interest Rate (Percentage)			4.01%		4.01%
Due Date					2,030
AEP Transmission Company, LLC [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 50,000
Interest Rate (Percentage)			3.66%		3.66%
Due Date					2,025
AEP Transmission Company, LLC [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 40,000
Interest Rate (Percentage)			3.76%		3.76%
Due Date					2,025
Kentucky Power Co [Member] | Other Long Term Debt One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 25,000
Interest Rate (Variable)					Variable
Due Date					2,018
Transource Missouri [Member] | Other Long Term Debt One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 13,000
Interest Rate (Variable)					Variable
Due Date					2,018
AEP Generation Resources [Member] | Other Long Term Debt One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 500,000
Interest Rate (Variable)					Variable
Due Date					2,017
AEP Generation Resources [Member] | Other Long Term Debt Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Retirements and Principal Payments					$ 500,000
Interest Rate (Variable)					Variable
Due Date					2,015
Wheeling Power Co [Member] | Senior Unsecured Notes One [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 113,000
Interest Rate (Percentage)			3.36%		3.36%
Due Date					2,022
Wheeling Power Co [Member] | Senior Unsecured Notes Two [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 122,000
Interest Rate (Percentage)			3.70%		3.70%
Due Date					2,025
Wheeling Power Co [Member] | Senior Unsecured Notes Three [Member]
Long-term Debt and Other Securities Issued, Retired and Principal Payments Made
Issuances					$ 50,000
Interest Rate (Percentage)			4.20%		4.20%
Due Date					2,035
[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 June 30, 2015 and December 31, 2014, 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 issuance amount.
[3]	Amount of securitized debt for receivables as accounted for under the ''Transfers and Servicing'' accounting guidance
[4]	Weighted average rate.
[5]	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.

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Thousands		3 Months Ended			6 Months Ended			12 Months Ended
		Jun. 30, 2015		Jun. 30, 2014	Jun. 30, 2015		Jun. 30, 2014	Dec. 31, 2014
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		$ 2,200,000			$ 2,200,000			$ 2,380,000
Securitized Transition Assets		1,931,000			$ 1,931,000			2,072,000
AEP Credit, Inc. [Member]
Variable Interest Entities (Textuals) [Abstract]
Minimum Percentage of Equity AEP Provides					5.00%
Percentage of Short Term Borrowing Needs in Excess of Third Party Financings					20.00%
AEP Texas Central Transition Funding Co [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		1,600,000			$ 1,600,000			1,800,000
Securitized Transition Assets		1,500,000			1,500,000			1,600,000
Protected Cell Of Energy Insurance Services, Inc. [Member]
Variable Interest Entities (Textuals) [Abstract]
Insurance Premium Expense to Protected Cell		0		$ 1,400	14,000		$ 18,000
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Proceeds from Partnership Contribution					17,000			23,000
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		21,000			21,000			21,000
Maximum Exposure		21,000			21,000			21,000
Advance Due to 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		56,000			56,000			56,000
Maximum Exposure		56,000			56,000			56,000
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			19,000			19,000
Maximum Exposure		19,000			19,000			19,000
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		2,000			2,000			2,000
Maximum Exposure		2,000			2,000			2,000
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			0
Maximum Exposure		50,000			50,000			48,000
Current Assets [Member] | AEP Credit, Inc. [Member]
ASSETS
Assets		986,000			986,000			980,000
Current Assets [Member] | AEP Texas Central Transition Funding Co [Member]
ASSETS
Assets		220,000			220,000			239,000
Current Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member]
ASSETS
Assets		155,000			155,000			149,000
Current Assets [Member] | Transource Energy [Member]
ASSETS
Assets		10,000			10,000			2,000
Net Property Plant And Equipment [Member] | AEP Credit, Inc. [Member]
ASSETS
Assets		0			0			0
Net Property Plant And Equipment [Member] | AEP Texas Central Transition Funding Co [Member]
ASSETS
Assets		0			0			0
Net Property Plant And Equipment [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member]
ASSETS
Assets		0			0			0
Net Property Plant And Equipment [Member] | Transource Energy [Member]
ASSETS
Assets		137,000			137,000			98,000
Other Non Current Assets [Member] | AEP Credit, Inc. [Member]
ASSETS
Assets		0			0			0
Other Non Current Assets [Member] | AEP Texas Central Transition Funding Co [Member]
ASSETS
Assets		1,533,000	[1]		1,533,000	[1]		1,654,000	[2]
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation		72,000			72,000			75,000
Other Non Current Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member]
ASSETS
Assets		1,000			1,000			2,000
Other Non Current Assets [Member] | Transource Energy [Member]
ASSETS
Assets		5,000			5,000			4,000
Total Assets [Member] | AEP Credit, Inc. [Member]
ASSETS
Assets		986,000			986,000			980,000
Total Assets [Member] | AEP Texas Central Transition Funding Co [Member]
ASSETS
Assets		1,753,000			1,753,000			1,893,000
Total Assets [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member]
ASSETS
Assets		156,000			156,000			151,000
Total Assets [Member] | Transource Energy [Member]
ASSETS
Assets		152,000			152,000			104,000
Current Liabilities [Member] | AEP Credit, Inc. [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		886,000			886,000			894,000
Current Liabilities [Member] | AEP Texas Central Transition Funding Co [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		326,000			326,000			322,000
Current Liabilities [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		43,000			43,000			44,000
Current Liabilities [Member] | Transource Energy [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		28,000			28,000			21,000
Noncurrent Liabilities [Member] | AEP Credit, Inc. [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		0			0			0
Noncurrent Liabilities [Member] | AEP Texas Central Transition Funding Co [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		1,409,000			1,409,000			1,553,000
Noncurrent Liabilities [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		67,000			67,000			62,000
Noncurrent Liabilities [Member] | Transource Energy [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		70,000			70,000			55,000
Equity [Member] | AEP Credit, Inc. [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		100,000			100,000			86,000
Equity [Member] | AEP Texas Central Transition Funding Co [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		18,000			18,000			18,000
Equity [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		46,000			46,000			45,000
Equity [Member] | Transource Energy [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		54,000			54,000			28,000
Total Liabilities And Equity [Member] | AEP Credit, Inc. [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		986,000			986,000			980,000
Total Liabilities And Equity [Member] | AEP Texas Central Transition Funding Co [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		1,753,000			1,753,000			1,893,000
Total Liabilities And Equity [Member] | Protected Cell Of Energy Insurance Services, Inc. [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		156,000			156,000			151,000
Total Liabilities And Equity [Member] | Transource Energy [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 152,000			$ 152,000			104,000
Great Plains Energy Inc. [Member] | Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage		13.50%			13.50%
Transource Energy [Member]
Variable Interest Entities (Textuals) [Abstract]
Equity and Voting Ownership Percentage		86.50%			86.50%
Appalachian Power Co [Member]
Related Party Transaction, Due from (to) Related Party, Current		$ (33,703)			$ (33,703)
Variable Interest Entities (Textuals) [Abstract]
Securitized Transition Assets		339,020			339,020			350,170
Appalachian Power Co [Member] | Appalachian Consumer Rate Relief Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		357,000			357,000			368,000
Securitized Transition Assets		339,000			339,000			350,000
Intercompany Item Eliminated in Consolidation		4,000			4,000			4,000
Appalachian Power Co [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Affiliates
Billings from VIE		52,722		53,959	100,970		104,096
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		52,722		53,959	100,970		104,096
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		19,141			19,141			30,692
Maximum Exposure		19,141			19,141			30,692
Appalachian Power Co [Member] | Current Assets [Member] | Appalachian Consumer Rate Relief Funding [Member]
ASSETS
Assets		19,145			19,145			18,099
Appalachian Power Co [Member] | Other Non Current Assets [Member] | Appalachian Consumer Rate Relief Funding [Member]
ASSETS
Assets	[3]	346,809			346,809			358,264
Appalachian Power Co [Member] | Total Assets [Member] | Appalachian Consumer Rate Relief Funding [Member]
ASSETS
Assets		365,954			365,954			376,363
Appalachian Power Co [Member] | Current Liabilities [Member] | Appalachian Consumer Rate Relief Funding [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		26,912			26,912			26,809
Appalachian Power Co [Member] | Noncurrent Liabilities [Member] | Appalachian Consumer Rate Relief Funding [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		337,316			337,316			347,652
Appalachian Power Co [Member] | Equity [Member] | Appalachian Consumer Rate Relief Funding [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		1,726			1,726			1,902
Appalachian Power Co [Member] | Total Liabilities And Equity [Member] | Appalachian Consumer Rate Relief Funding [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		365,954			365,954			376,363
Indiana Michigan Power Co [Member]
Related Party Transaction, Due from (to) Related Party, Current		(127,154)			(127,154)
Indiana Michigan Power Co [Member] | DCC Fuel [Member]
Variable Interest Entities (Textuals) [Abstract]
Payments Made by I&M to DCC Fuel		34,000		32,000	57,000		56,000
Indiana Michigan Power Co [Member] | Billings from AEP Generating Co [Member]
Billings from Affiliates
Billings from VIE		59,993		65,190	114,958		135,612
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		59,993		65,190	114,958		135,612
Indiana Michigan Power Co [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Affiliates
Billings from VIE		31,134		30,103	64,636		62,073
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		31,134		30,103	64,636		62,073
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		11,173			11,173			22,480
Maximum Exposure		11,173			11,173			22,480
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		21,084			21,084			20,031
Maximum Exposure		21,084			21,084			20,031
Indiana Michigan Power Co [Member] | Current Assets [Member] | DCC Fuel [Member]
ASSETS
Assets		114,522			114,522			97,361
Indiana Michigan Power Co [Member] | Net Property Plant And Equipment [Member] | DCC Fuel [Member]
ASSETS
Assets		219,786			219,786			158,121
Indiana Michigan Power Co [Member] | Other Non Current Assets [Member] | DCC Fuel [Member]
ASSETS
Assets		117,702			117,702			79,705
Indiana Michigan Power Co [Member] | Total Assets [Member] | DCC Fuel [Member]
ASSETS
Assets		452,010			452,010			335,187
Indiana Michigan Power Co [Member] | Current Liabilities [Member] | DCC Fuel [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		109,491			109,491			86,026
Indiana Michigan Power Co [Member] | Noncurrent Liabilities [Member] | DCC Fuel [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		342,519			342,519			249,161
Indiana Michigan Power Co [Member] | Total Liabilities And Equity [Member] | DCC Fuel [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		452,010			452,010			335,187
Public Service Co Of Oklahoma [Member]
Related Party Transaction, Due from (to) Related Party, Current		64,212			64,212
Public Service Co Of Oklahoma [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Affiliates
Billings from VIE		24,442		22,889	47,966		47,329
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		24,442		22,889	47,966		47,329
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		9,017			9,017			15,338
Maximum Exposure		9,017			9,017			15,338
Southwestern Electric Power Co [Member]
Related Party Transaction, Due from (to) Related Party, Current		179,709			179,709
Southwestern Electric Power Co [Member] | Sabine Mining Co [Member]
Billings from Affiliates
Billings from VIE		41,000		41,000	83,000		80,000
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		41,000		41,000	83,000		80,000
Southwestern Electric Power Co [Member] | Dolet Hills Lignite Co, LLC [Member]
Related Party Transaction, Due from (to) Related Party, Current		56,000			56,000			56,000
Investments in and Advance to Affiliates, Subsidiaries, Associates, and Joint Ventures [Abstract]
As Reported on the Consolidated Balance Sheet		13,183			13,183			11,462
Maximum Exposure		119,591			119,591			115,796
Billings from Affiliates
Billings from VIE		15,000		6,000	29,000		8,000
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		15,000		6,000	$ 29,000		8,000
Percentage of VIE Sales of Lignite Produced					50.00%
Percentage of DHLCs Debt Guaranteed by Each SWEPCo and CLECO					50.00%
Percentage Of VIE Management Fee Received					100.00%
Southwestern Electric Power Co [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Affiliates
Billings from VIE		31,900		32,718	$ 63,414		65,741
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		31,900		32,718	63,414		65,741
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		12,114			12,114			20,772
Maximum Exposure		12,114			12,114			20,772
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			7,643			7,643
Maximum Exposure		7,643			7,643			7,643
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		5,540			5,540			3,819
Maximum Exposure		5,540			5,540			3,819
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			0
Maximum Exposure	[4]	106,408			106,408			104,334
Southwestern Electric Power Co [Member] | Current Assets [Member] | Sabine Mining Co [Member]
ASSETS
Assets		57,592			57,592			67,981
Southwestern Electric Power Co [Member] | Net Property Plant And Equipment [Member] | Sabine Mining Co [Member]
ASSETS
Assets		142,265			142,265			145,491
Southwestern Electric Power Co [Member] | Other Non Current Assets [Member] | Sabine Mining Co [Member]
ASSETS
Assets		59,717			59,717			51,578
Southwestern Electric Power Co [Member] | Total Assets [Member] | Sabine Mining Co [Member]
ASSETS
Assets		259,574			259,574			265,050
Southwestern Electric Power Co [Member] | Current Liabilities [Member] | Sabine Mining Co [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		28,122			28,122			36,286
Southwestern Electric Power Co [Member] | Noncurrent Liabilities [Member] | Sabine Mining Co [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		231,155			231,155			228,349
Southwestern Electric Power Co [Member] | Equity [Member] | Sabine Mining Co [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		297			297			415
Southwestern Electric Power Co [Member] | Total Liabilities And Equity [Member] | Sabine Mining Co [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 259,574			$ 259,574			265,050
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 1) [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share		50.00%			50.00%
AEP Generating Co [Member] | Rockport Generating Plant (Unit No. 2) [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage Interest in Rockport Plant Unit 2 Lease		50.00%			50.00%
AEP Generating Co [Member] | Lawrenceburg Generating Station [Member]
Variable Interest Entities (Textuals) [Abstract]
Jointly Owned Utility Plant, Proportionate Ownership Share		100.00%			100.00%
Cleco Power, LLC [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage of VIE Sales of Lignite Produced					50.00%
First Energy Corp [Member] | Allegheny Series [Member]
Variable Interest Entities (Textuals) [Abstract]
Percentage Ownership of "Allegheny Series" by a Nonaffiliated Company					100.00%
Ohio Power Co [Member]
Related Party Transaction, Due from (to) Related Party, Current		$ 187,812			$ 187,812
Variable Interest Entities (Textuals) [Abstract]
Securitized Transition Assets		97,849			97,849			109,999
Ohio Power Co [Member] | Billings from American Electric Power Service Corporation [Member]
Billings from Affiliates
Billings from VIE		40,907		40,441	80,137		79,490
Variable Interest Entities (Textuals) [Abstract]
Billings from VIE		40,907		$ 40,441	80,137		$ 79,490
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		15,423			15,423			24,695
Maximum Exposure		15,423			15,423			24,695
Ohio Power Co [Member] | Ohio Phase-In-Recovery Funding [Member]
Variable Interest Entities (Textuals) [Abstract]
Securitization Bonds		210,000			210,000			232,000
Securitized Transition Assets		98,000			98,000			110,000
Ohio Power Co [Member] | Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member]
ASSETS
Assets		32,778			32,778			32,676
Ohio Power Co [Member] | Other Non Current Assets [Member] | Ohio Phase-In-Recovery Funding [Member]
ASSETS
Assets	[5]	186,609			186,609			209,922
Variable Interest Entities (Textuals) [Abstract]
Intercompany Item Eliminated in Consolidation		87,000			87,000			97,000
Ohio Power Co [Member] | Total Assets [Member] | Ohio Phase-In-Recovery Funding [Member]
ASSETS
Assets		219,387			219,387			242,598
Ohio Power Co [Member] | Current Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		47,539			47,539			47,099
Ohio Power Co [Member] | Noncurrent Liabilities [Member] | Ohio Phase-In-Recovery Funding [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		170,511			170,511			194,162
Ohio Power Co [Member] | Equity [Member] | Ohio Phase-In-Recovery Funding [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		1,337			1,337			1,337
Ohio Power Co [Member] | Total Liabilities And Equity [Member] | Ohio Phase-In-Recovery Funding [Member]
LIABILITIES AND EQUITY
Liabilities and Equity		$ 219,387			$ 219,387			$ 242,598
[1]	(a)Includes an intercompany item eliminated in consolidation of $72 million
[2]	(a)Includes an intercompany item eliminated in consolidation of $75 million
[3]	(a)Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $4 million and $4 million, respectively.
[4]	(a)Includes affiliate advances due to Parent related to participation in the Utility Money Pool of $56 million and $56 million in 2015 and 2014, respectively.
[5]	(a)Includes an intercompany item eliminated in consolidation as of June 30, 2015 and December 31, 2014 of $87 million and $97 million, respectively.

Disposition Plant Severance (De

Disposition Plant Severance (Details) - USD ($) $ in Thousands		6 Months Ended	12 Months Ended
		Jun. 30, 2015	Dec. 31, 2014
Severance Costs			$ 29,000
Vertically Integrated Utilities [Member]
Cost Reduction Initiatives Text [Abstract]
Current Period Severance Costs Percentage		68.00%
Generation And Marketing [Member]
Cost Reduction Initiatives Text [Abstract]
Current Period Severance Costs Percentage		32.00%
Disposition Plant Severance [Member]
Cost Reduction Initiatives [Abstract]
Beginning Balance		$ 29,000
Incurred		3,000
Settled		(11,000)
Adjustments		0
Remaining Balance		21,000	29,000
Appalachian Power Co [Member]
Severance Costs			7,112
Cost Reduction Initiatives [Abstract]
Beginning Balance		9,304
Expense Allocation from Aepsc		(5)
Incurred		817
Settled	[1]	(4,478)
Adjustments		(129)
Remaining Balance		5,509	9,304
Indiana Michigan Power Co [Member]
Severance Costs			8,185
Cost Reduction Initiatives [Abstract]
Beginning Balance		8,023
Expense Allocation from Aepsc		(3)
Incurred		363
Settled		(3,459)
Adjustments		0
Remaining Balance		4,924	8,023
Ohio Power Co [Member]
Severance Costs			80
Public Service Co Of Oklahoma [Member]
Severance Costs			288
Cost Reduction Initiatives [Abstract]
Beginning Balance		134
Expense Allocation from Aepsc		(3)
Incurred		416
Settled		(116)
Adjustments		0
Remaining Balance		431	134
Southwestern Electric Power Co [Member]
Severance Costs			289
Cost Reduction Initiatives [Abstract]
Beginning Balance		84
Expense Allocation from Aepsc		(4)
Incurred		0
Settled		(79)
Adjustments		0
Remaining Balance		$ 1	$ 84
[1]	Settled includes amounts received from affiliates for expenses related to joint plant.

Property, Plant and Equipment56

Property, Plant and Equipment Property, Plant and Equipment (Details) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2015	Dec. 31, 2014
Asset Retirement Obligations (ARO)
Beginning Balance		$ 2,019,000
Accretion Expense		50,000
Liabilities Incurred		47,000
Liabilities Settled		(22,000)
Revisions in Cash Flow Estimates		48,000
Ending Balance		2,142,000
Property, Plant and Equipment (Textuals) [Abstract]
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant		1,300,000	$ 1,300,000
Fair Value of Legally Restricted Assets		1,800,000	1,800,000
Appalachian Power Co [Member]
Asset Retirement Obligations (ARO)
Beginning Balance	[1],[2]	148,377
Accretion Expense		4,122
Liabilities Incurred		0
Liabilities Settled		(10,503)
Revisions in Cash Flow Estimates		13,962
Ending Balance	[1],[2]	155,958
Indiana Michigan Power Co [Member]
Asset Retirement Obligations (ARO)
Beginning Balance	[1],[2],[3]	1,342,549
Accretion Expense		31,731
Liabilities Incurred		0
Liabilities Settled		(1,222)
Revisions in Cash Flow Estimates		5,639
Ending Balance	[1],[2],[3]	1,378,697
Property, Plant and Equipment (Textuals) [Abstract]
Asset Retirement Obligations (ARO) Liability for Nuclear Decommissioning of the Cook Plant		1,300,000	1,300,000
Fair Value of Legally Restricted Assets		1,800,000	$ 1,800,000
Ohio Power Co [Member]
Asset Retirement Obligations (ARO)
Beginning Balance	[1],[4]	1,361
Accretion Expense		41
Liabilities Incurred		0
Liabilities Settled		(8)
Revisions in Cash Flow Estimates		0
Ending Balance	[1],[4]	1,394
Public Service Co Of Oklahoma [Member]
Asset Retirement Obligations (ARO)
Beginning Balance	[1],[2]	38,020
Accretion Expense		1,214
Liabilities Incurred		5,336
Liabilities Settled		(115)
Revisions in Cash Flow Estimates		1,916
Ending Balance	[1],[2]	46,371
Southwestern Electric Power Co [Member]
Asset Retirement Obligations (ARO)
Beginning Balance	[1],[2],[5]	94,394
Accretion Expense		2,725
Liabilities Incurred		12,191
Liabilities Settled		(2,189)
Revisions in Cash Flow Estimates		6,348
Ending Balance	[1],[2],[5]	$ 113,469
[1]	Includes ARO related to asbestos removal.
[2]	Includes ARO related to ash disposal facilities.
[3]	Includes ARO related to nuclear decommissioning costs for the Cook Plant of $1.3 billion and $1.3 billion as of June 30, 2015 and December 31, 2014.
[4]	Not impacted by the CCR rule.
[5]	Includes ARO related to Sabine and DHLC.

Uncategorized Items - aep-20150

Label	Element	Value
Carrying Costs Income	aep_CarryingCostsIncome	$ 9,000
Carrying Costs Income	aep_CarryingCostsIncome	9,000
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	25,000
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	34,000
Appalachian Power Co [Member]
Carrying Costs Income	aep_CarryingCostsIncome	263
Carrying Costs Income	aep_CarryingCostsIncome	417
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	1,625
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	3,897
Indiana Michigan Power Co [Member]
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	2,907
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	4,804
Ohio Power Co [Member]
Carrying Costs Income	aep_CarryingCostsIncome	5,153
Carrying Costs Income	aep_CarryingCostsIncome	6,874
Amortization Of Generation Deferrals	aep_AmortizationOfGenerationDeferrals	24,977
Amortization Of Generation Deferrals	aep_AmortizationOfGenerationDeferrals	35,301
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	1,342
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	2,343
Public Service Co Of Oklahoma [Member]
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	2,283
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	590
Southwestern Electric Power Co [Member]
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	2,197
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	us-gaap_PublicUtilitiesAllowanceForFundsUsedDuringConstructionCapitalizedCostOfEquity	$ 5,882