American Electric Power (AEP) 10-Q 30 Oct 09 2009 Q3 Quarterly report Financial data

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (USD $)
In Millions, except Share data	3 Months Ended Sep. 30, 2009	3 Months Ended Sep. 30, 2008	9 Months Ended Sep. 30, 2009	9 Months Ended Sep. 30, 2008
Revenues
Utility Operations	$3,364	$4,108	$9,666	$10,318
Other Revenues	183	83	541	886
TOTAL REVENUES	3,547	4,191	10,207	11,204
Expenses
Fuel and Other Consumables Used for Electric Generation	931	1,480	2,624	3,513
Purchased Electricity for Resale	247	394	800	1,023
Other Operation and Maintenance	899	1,010	2,724	2,870
Gain on Sales of Assets, Net	(2)	(6)	(13)	(14)
Asset Impairments and Other Related Charges	0	0	0	(255)
Depreciation and Amortization	421	387	1,200	1,123
Taxes Other Than Income Taxes	193	189	582	578
TOTAL EXPENSES	2,689	3,454	7,917	8,838
OPERATING INCOME	858	737	2,290	2,366
Other Income (Expense):
Interest and Investment Income	5	14	5	45
Carrying Costs Income	12	21	33	64
Allowance for Equity Funds Used During Construction	23	11	59	32
Interest Expense	(248)	(216)	(726)	(669)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	650	567	1,661	1,838
Income Tax Expense	208	192	535	608
Equity Earnings of Unconsolidated Subsidiaries	4	1	5	3
INCOME BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY LOSS	446	376	1,131	1,233
DISCONTINUED OPERATIONS, NET OF TAX	0	0	0	1
INCOME BEFORE EXTRAORDINARY LOSS	446	376	1,131	1,234
EXTRAORDINARY LOSS, NET OF TAX	0	0	(5)	0
NET INCOME	446	376	1,126	1,234
Less: Net Income Attributable to Noncontrolling Interests	2	1	5	4
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS	444	375	1,121	1,230
Less: Preferred Stock Dividend Requirements of Subsidiaries	1	1	2	2
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$443	$374	$1,119	$1,228
Earnings Per Share
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	476,948,143	402,286,779	452,255,119	401,535,661
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Discontinued Operations and Extraordinary Loss	0.93	0.93	2.48	3.06
Discontinued Operations, Net of Tax	$0	$0	$0	$0
Income Before Extraordinary Loss	0.93	0.93	2.48	3.06
Extraordinary Loss, Net of Tax	$0	$0	-0.01	$0
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	0.93	0.93	2.47	3.06
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	477,111,144	403,910,309	452,495,494	402,925,534
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Discontinued Operations and Extraordinary Loss	0.93	0.93	2.48	3.05
Discontinued Operations, Net of Tax	$0	$0	$0	$0
Income Before Extraordinary Loss	0.93	0.93	2.48	3.05
Extraordinary Loss, Net of Tax	$0	$0	-0.01	$0
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	0.93	0.93	2.47	3.05
CASH DIVIDENDS PAID PER SHARE	0.41	0.41	1.23	1.23

Condensed Consolidated Balance

Condensed Consolidated Balance Sheet (USD $)
In Millions	Sep. 30, 2009	Dec. 31, 2008
Current Assets
Cash and Cash Equivalents	$877	$411
Other Temporary Investments	259	327
Accounts Receivable:
Customers	600	569
Accrued Unbilled Revenues	402	449
Miscellaneous	63	90
Allowance for Uncollectible Accounts	(36)	(42)
Total Accounts Receivable	1,029	1,066
Fuel	998	634
Materials and Supplies	569	539
Risk Management Assets	300	256
Regulatory Asset for Under-Recovered Fuel Costs	103	284
Margin Deposits	101	86
Prepayments and Other Current Assets	243	172
TOTAL CURRENT ASSETS	4,479	3,775
Electric:
Production	22,552	21,242
Transmission	8,198	7,938
Distribution	13,336	12,816
Other Property, Plant and Equipment (including coal mining and nuclear fuel)	3,821	3,741
Construction Work in Progress	3,251	3,973
Total Property, Plant and Equipment	51,158	49,710
Accumulated Depreciation and Amortization	17,337	16,723
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	33,821	32,987
Other Noncurrent Assets
Regulatory Assets	4,360	3,783
Securitized Transition Assets	1,940	2,040
Spent Nuclear Fuel and Decommissioning Trusts	1,364	1,260
Goodwill	76	76
Long-term Risk Management Assets	379	355
Deferred Charges and Other Noncurrent Assets	774	879
TOTAL OTHER NONCURRENT ASSETS	8,893	8,393
TOTAL ASSETS	47,193	45,155
Current Liabilities
Accounts Payable	1,004	1,297
Short-term Debt	352	1,976
Long-term Debt Due Within One Year	1,540	447
Risk Management Liabilities	136	134
Customer Deposits	265	254
Accrued Taxes	470	634
Accrued Interest	232	270
Regulatory Liability for Over-Recovered Fuel Costs	107	66
Other Current Liabilities	881	1,219
TOTAL CURRENT LIABILITIES	4,987	6,297
Noncurrent Liabilities
Long-term Debt	15,713	15,536
Long-term Risk Management Liabilities	150	170
Deferred Income Taxes	5,824	5,128
Regulatory Liabilities and Deferred Investment Tax Credits	2,901	2,789
Asset Retirement Obligations	1,197	1,154
Employee Benefits and Pension Obligations	2,168	2,184
Deferred Credits and Other Noncurrent Liabilities	1,128	1,126
TOTAL NONCURRENT LIABILITIES	29,081	28,087
TOTAL LIABILITIES	34,068	34,384
Cumulative Preferred Stock Not Subject to Mandatory Redemption	61	61
Equity
Common Stock Par Value $6.50:	3,235	2,771
Paid-in Capital	5,826	4,527
Retained Earnings	4,407	3,847
Accumulated Other Comprehensive Income (Loss)	(404)	(452)
TOTAL AEP COMMON SHAREHOLDERS' EQUITY	13,064	10,693
Noncontrolling Interests	0	17
TOTAL EQUITY	13,064	10,710
TOTAL LIABILITIES AND EQUITY	$47,193	$45,155

Parenthetical Information for C

Parenthetical Information for Condensed Consolidated Balance Sheet (USD $)
	Sep. 30, 2009	Dec. 31, 2008
Equity
Common Stock, Par Value Per Share	6.5	6.5
Common Stock, Shares Authorized	600,000,000	600,000,000
Common Stock, Shares, Issued	497,649,344	426,321,248
Treasury Stock, Shares	20,249,992	20,249,992

1_Condensed Consolidated Statem

Condensed Consolidated Statements of Cash Flow (USD $)
In Millions	9 Months Ended Sep. 30, 2009	9 Months Ended Sep. 30, 2008
Operating Activites
Net Income	$1,126	$1,234
Less: Discontinued Operations, Net of Tax	0	(1)
Income Before Discontinued Operations	1,126	1,233
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	1,200	1,123
Deferred Income Taxes	662	397
Extraordinary Loss, Net of Tax	5	0
Carrying Costs Income	(33)	(64)
Allowance for Equity Funds Used During Construction	(59)	(32)
Mark-to-Market of Risk Management Contracts	(99)	14
Amortization of Nuclear Fuel	41	72
Deferred Property Taxes	144	136
Fuel Over/Under-Recovery, Net	(377)	(284)
Gain on Sales of Assets, Net	(13)	(14)
Change in Other Noncurrent Assets	26	(160)
Change in Other Noncurrent Liabilities	164	(74)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	68	(69)
Fuel, Materials and Supplies	(394)	(49)
Margin Deposits	(15)	(20)
Accounts Payable	(29)	77
Customer Deposits	11	(14)
Accrued Taxes, Net	(165)	(40)
Accrued Interest	(38)	(5)
Other Current Assets	(71)	(43)
Other Current Liabilities	(283)	(125)
Net Cash Flows from Operating Activities	1,871	2,059
Investing Activities
Construction Expenditures	(2,123)	(2,576)
Change in Other Temporary Investments, Net	72	106
Purchases of Investment Securities	(573)	(1,386)
Sales of Investment Securities	524	912
Acquisitions of Nuclear Fuel	(153)	(99)
Acquisitions of Assets	(70)	(97)
Proceeds from Sales of Assets	258	83
Other Investing Activities	(32)	(4)
Net Cash Flows Used for Investing Activities	(2,097)	(3,061)
Financing Activities
Issuance of Common Stock, Net	1,706	106
Issuance of Long-term Debt	1,912	2,561
Change in Short-term Debt, Net	(1,624)	642
Retirement of Long-term Debt	(659)	(1,582)
Principal Payments for Capital Lease Obligations	(62)	(76)
Dividends Paid on Common Stock	(564)	(500)
Dividends Paid on Cumulative Preferred Stock	(2)	(2)
Other Financing Activities	(15)	13
Net Cash Flows from Financing Activities	692	1,162
Net Increase in Cash and Cash Equivalents	466	160
Cash and Cash Equivalents at Beginning of Period	411	178
Cash and Cash Equivalents at End of Period	877	338
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	744	657
Net Cash Paid (Received) for Income Taxes	(74)	126
Noncash Acquisitions Under Capital Leases	53	47
Noncash Acquisition of Land/Mineral Rights	0	42
Construction Expenditures Included in Accounts Payable at September 30,	229	373
Acquisition of Nuclear Fuel Included in Accounts Payable at September 30,	$0	$66

2_Condensed Consolidated Statem

Condensed Consolidated Statements of Change in Equity and Comprehensive Income (Loss) (USD $)
In Millions	9 Months Ended Sep. 30, 2009	9 Months Ended Sep. 30, 2008
Beginning Balance	$10,710	$10,097
Shares Issued, Beginning Balance	426
EITF 06-10 Adoption, Net of Tax		(10)
SFAS 157 Adoption, Net of Tax		(1)
Issuance of Common Stock, Value	1,758	106
Common Stock Dividends	(564)	(500)
Preferred Stock Dividends	(2)	(2)
Purchase of JMG	37
Other Changes in Equity	(49)	4
Subtotal - Equity	11,890	9,694
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax	5	7
Securities Available for Sale, Net of Tax	10	(10)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	33	9
Net Income	1,126	1,234
Total Comprehensive Income	1,174	1,240
Ending Balance	13,064	10,934
Shares Issued, Ending Balance	498
Common Stock
Beginning Balance	2,771	2,743
Shares Issued, Beginning Balance	426	422
Issuance of Common Stock, Value	464	17
Issuance of Common Stock, Shares	71	3
Other Comprehensive Income (Loss), Net of Taxes:
Ending Balance	3,235	2,760
Shares Issued, Ending Balance	497	425
Additional Paid-in Capital
Beginning Balance	4,527	4,352
Issuance of Common Stock, Value	1,294	89
Purchase of JMG	55
Other Changes in Equity	(50)	3
Other Comprehensive Income (Loss), Net of Taxes:
Ending Balance	5,826	4,444
Retained Earnings
Beginning Balance	3,847	3,138
EITF 06-10 Adoption, Net of Tax		(10)
SFAS 157 Adoption, Net of Tax		(1)
Common Stock Dividends	(559)	(494)
Preferred Stock Dividends	(2)	(2)
Other Comprehensive Income (Loss), Net of Taxes:
Net Income	1,121	1,230
Ending Balance	4,407	3,861
Accumulated Other Comprehensive Income
Beginning Balance	(452)	(154)
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax	5	7
Securities Available for Sale, Net of Tax	10	(10)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	33	9
Ending Balance	(404)	(148)
Noncontrolling Interest
Beginning Balance	17	18
Common Stock Dividends	(5)	(6)
Purchase of JMG	(18)
Other Changes in Equity	1	1
Other Comprehensive Income (Loss), Net of Taxes:
Net Income	5	4
Ending Balance	$0	$17

3_Parenthetical Information for

Parenthetical Information for Condensed Consolidate Statements of Changes in Common Shareholders' Equity and Comprehensive Income (Loss) (USD $)
In Millions	9 Months Ended Sep. 30, 2009	9 Months Ended Sep. 30, 2008
Statement of Stockholders' Equity [Abstract]
EITF 06-10 Adoption, Tax		$6
SFAS 157 Adoption, Tax		0
Cash Flow Hedges, Tax	3	4
Securities Available for Sale, Tax	5	5
Amortization of Pension and OPEB Deferred Costs, Tax	$18	$5

Significant Accounting Matters

Significant Accounting Matters
	9 Months Ended Sep. 30, 2009 USD / shares
Summary of Significant Accounting Policies [Abstract]
Significant Accounting Matters	SIGNIFICANT ACCOUNTING MATTERS General The accompanying 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 nine months ended September 30, 2009 is not necessarily indicative of results that may be expected for the year ending December 31, 2009.We reviewed subsequent events through our Form 10-Q issuance date of October 30, 2009.The accompanying condensed consolidated financial statements are unaudited and should be read in conjunction with the audited 2008 consolidated financial statements and notes thereto, which are included in our Current Report on Form 8-K as filed with the SEC on May 1, 2009. Earnings Per Share (EPS) The following table presents our basic and diluted EPS calculations included on our Condensed Consolidated Statements of Income: Three Months Ended September 30, 2009 2008 (in millions, except per share data) $/share $/share Earnings Applicable to AEP Common Shareholders $ 443 $ 374 Weighted Average Number of Basic Shares Outstanding 476.9 $ 0.93 402.3 $ 0.93 Weighted Average Dilutive Effect of: Performance Share Units 0.1 - 1.3 - Stock Options - - 0.1 - Restricted Stock Units 0.1 - 0.1 - Restricted Shares - - 0.1 - Weighted Average Number of Diluted Shares Outstanding 477.1 $ 0.93 403.9 $ 0.93 Nine Months Ended September 30, 2009 2008 (in millions, except per share data) $/share $/share Earnings Applicable to AEP Common Shareholders $ 1,119 $ 1,228 Weighted Average Number of Basic Shares Outstanding 452.3 $ 2.47 401.5 $ 3.06 Weighted Average Dilutive Effect of: Performance Share Units 0.2 - 1.0 (0.01 ) Stock Options - - 0.2 - Restricted Stock Units - - 0.1 - Restricted Shares - - 0.1 - Weighted Average Number of Diluted Shares Outstanding 452.5 $ 2.47 402.9 $ 3.05 The assumed conversion of our share-based compensation does not affect net earnings for purposes of calculating diluted earnings per share. Options to purchase 612,916 and 146,900 shares of common stock were outstanding at September 30, 2009 and 2008, respectively, but were not included in the computation of diluted ea

New Accounting Pronouncements a

New Accounting Pronouncements and Extraordinary Item
	9 Months Ended Sep. 30, 2009 USD / shares
New Accounting Pronouncements [Abstract]
New Accounting Pronouncements and Extraordinary Item	NEW ACCOUNTING PRONOUNCEMENTS AND EXTRAORDINARY ITEM 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 represents a summary of final pronouncements issued or implemented in 2009 and standards issued but not implemented that we have determined relate to our operations. Pronouncements Adopted During 2009 The following standards were effective during the first nine months of 2009.Consequently, the financial statements and footnotes reflect their impact. SFAS 141 (revised 2007) Business Combinations (SFAS 141R) In December 2007, the FASB issued SFAS 141R, improving financial reporting about business combinations and their effects.It established how the acquiring entity recognizes and measures the identifiable assets acquired, liabilities assumed, goodwill acquired, any gain on bargain purchases and any noncontrolling interest in the acquired entity.SFAS 141R no longer allows acquisition-related costs to be included in the cost of the business combination, but rather expensed in the periods they are incurred, with the exception of the costs to issue debt or equity securities which shall be recognized in accordance with other applicable GAAP.The standard requires disclosure of information for a business combination that occurs during the accounting period or prior to the issuance of the financial statements for the accounting period.SFAS 141R can affect tax positions on previous acquisitions.We do not have any such tax positions that result in adjustments. In April 2009, the FASB issued FSP SFAS 141(R)-1 Accounting for Assets Acquired and Liabilities Assumed in a Business Combination That Arise from Contingencies.The standard clarifies accounting and disclosure for contingencies arising in business combinations.It was effective January 1, 2009. We adopted SFAS 141R, including the FSP, effective January 1, 2009.It is effective prospectively for business combinations with an acquisition date on or after January 1, 2009.We had no business combinations in 2009.We will apply it to any future business combinations.SFAS 141R is included in the Business Combinations accounting guidance. SFAS 160 Noncontrolling Interests in Consolidated Financial Statements (SFAS 160) In December 2007, the FASB issued SFAS 160, modifying reporting for noncontrolling interest (minority interest) in consolidated financial statements.The statement requires noncontrolling interest be reported in equity and establishes a new framework for recognizing net income or loss and comprehensive income by the controlling interest.Upon deconsolidation due to loss of control over a subsidiary, the standard requires a fair value remeasurement of any remaining noncontrolling equity investment to be used to properly recognize the gain or loss.SFAS 160 requires specific disclosures regarding changes in equity interest of both the controlling and noncontrolling parties and presentation of the noncontrolling equity balance and income or loss for all periods presented. We adopted SFAS 160 effective January 1, 2009 and retrospectively

Rate Matters

Rate Matters
	9 Months Ended Sep. 30, 2009 USD / shares
Rate Matters [Abstract]
Rate Matters	RATE MATTERS As discussed in the 2008 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions.The Rate Matters note within our 2008 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 2009 and updates the 2008 Annual Report. Ohio Rate Matters Ohio Electric Security Plan Filings In March 2009, the PUCO issued an order, which was amended by a rehearing entry in July 2009, that modified and approved CSPCos and OPCos ESPs that established standard service offer rates.The ESPs will be in effect through 2011.The ESP order authorized revenue increases during the ESP period and capped the overall revenue increases for CSPCo to 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo to 8% in 2009, 7% in 2010 and 8% in 2011.CSPCo and OPCo implemented rates for the April 2009 billing cycle.In its July 2009 rehearing entry, the PUCO required CSPCo and OPCo to reduce rates implemented in April 2009 by $22 million and $27 million, respectively, on an annualized basis.CSPCo and OPCo are collecting the 2009 annualized revenue increase over the last nine months of 2009. The order provides a FAC for the three-year period of the ESP.The FAC increase will be phased in to avoid having the resultant rate increases exceed the ordered annual caps described above.The FAC increase before phase-in will be subject to quarterly true-ups to actual recoverable FAC costs and to annual accounting audits and prudency reviews.The order allows CSPCo and OPCo to defer unrecovered FAC costs resulting from the annual caps/phase-in plan and to accrue carrying charges on such deferrals at CSPCos and OPCos weighted average cost of capital.The deferred FAC balance at the end of the three-year ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. The FAC deferrals at September 30, 2009 were $36 million and $238 million for CSPCo and OPCo, respectively, inclusive of carrying charges at the weighted average cost of capital.In the July 2009 rehearing order, the PUCO once again rejected a proposal by several intervenors to offset the FAC costs with a credit for off-system sales margins.As a result, CSPCo and OPCo will retain the benefit of their share of the AEP Systems off-system sales. The PUCOs July 2009 rehearing entry among other things reversed the prior authorization to recover the cost of CSPCos recently acquired Waterford and Darby Plants.In July 2009, CSPCo filed an application for rehearing with the PUCO seeking authorization to sell or transfer the Waterford and Darby Plants. The PUCO also addressed several additional matters in the ESP order, which are described below: CSPCo should attempt to mitigate the costs of its gridSMART advanced metering proposal that will affect portions of its service territory by seeking funds under the American Recovery and Reinvestment Act of 2009.As a result, a rider was established to recover $32 million rela

Commitments, Guarantees and Con

Commitments, Guarantees and Contingencies
	9 Months Ended Sep. 30, 2009 USD / shares
Commitments Guarantees and Contigencies [Abstract]
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 adverse effect on our financial statements.The Commitments, Guarantees and Contingencies note within our 2008 Annual Report should be read in conjunction with this report. GUARANTEES We record certain immaterial liabilities for guarantees in accordance with the accounting guidance for Guarantees.There is no collateral held in relation to any guarantees in excess of our ownership percentages.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 (LOCs) with third parties.These LOCs cover items such as gas and electricity risk management contracts, construction contracts, insurance programs, security deposits and debt service reserves.As the Parent, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries.At September 30, 2009, the maximum future payments for all the LOCs issued under the two $1.5 billion credit facilities are approximately $98 million with maturities ranging from October 2009 to July 2010. We have a $627 million 3-year credit agreement.As of September 30, 2009, $372 million of letters of credit with maturities ranging from May 2010 to June 2010 were issued by subsidiaries under the $627 million 3-year credit agreement to support variable rate Pollution Control Bonds.We had a $350 million 364-day credit agreement that expired in April 2009. 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 in the amount of approximately $65 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 Mining Company (Sabine), a consolidated variable interest entity.This guarantee ends upon depletion of reserves and completion of final reclamation.Based on the latest study, we estimate the reserves will be depleted in 2029 with final reclamation completed by 2036.A new study is in process to include new, expanded areas of the mine.As of September 30, 2009, SWEPCo has collected approximately $42 million through a rider for final mine closure and reclamation costs, of which $2 million is recorded in Other Current Liabilities, $23 million is recorded in Deferred Credits and Other Noncurrent Liabilities and $17 million is recorded in Asset Retirement Obligations on our Condensed Consolidated Balance Sheets. Sabine charges SWEPCo, its only customer, all of its costs.SWEPCo passes these costs to custo

Acquisitions and Disposition

Acquisitions and Disposition
	9 Months Ended Sep. 30, 2009 USD / shares
Acquisitions and Dispositions [Abstract]
Acquisitions and Discontinued Operations	ACQUISITIONS 2009 Oxbow Mine Lignite (Utility Operations segment) In April 2009, SWEPCo agreed to purchase 50% of the Oxbow Mine lignite reserves for $13 million and DHLC agreed to purchase 100% of all associated mining equipment and assets for $16 million from the North American Coal Corporation and its affiliates, Red River Mining Company and Oxbow Property Company, LLC.Cleco Power LLC (Cleco) will acquire the remaining 50% interest in the lignite reserves for $13 million.SWEPCo expects to complete the transaction in the fourth quarter of 2009.Consummation of the transaction is subject to regulatory approval by the LPSC and the APSC and the transfer of other regulatory instruments.If approved, DHLC will acquire and own the Oxbow Mine mining equipment and related assets and it will operate the Oxbow Mine.The Oxbow Mine is located near Coushatta, Louisiana and will be used as one of the fuel sources for SWEPCos and Clecos jointly-owned Dolet Hills Generating Station. 2008 Erlbacher companies (AEP River Operations segment) In June 2008, AEP River Operations purchased certain barging assets from Missouri Barge Line Company, Missouri Dry Dock and Repair Company and Cape Girardeau Fleeting, Inc. (collectively known as Erlbacher companies) for $35 million.These assets were incorporated into AEP Rivers operations diversifying its customer base. DISCONTINUED OPERATIONS We determined that certain of our operations were discontinued operations and classified them as such for all periods presented.We recorded the following amounts in 2009 and 2008 related to discontinued operations: U.K. Generation (a) Three Months Ended September 30, (in millions) 2009 Revenue $ - 2009 Pretax Income - 2009 Earnings,Net of Tax - 2008 Revenue $ - 2008 Pretax Income - 2008 Earnings,Net of Tax - U.K. Generation (a) Nine Months Ended September 30, (in millions) 2009 Revenue $ - 2009 Pretax Income - 2009 Earnings,Net of Tax - 2008 Revenue $ - 2008 Pretax Income 2 2008 Earnings,Net of Tax 1 (a) The 2008 amounts relate to final proceeds received for the sale of land related to the sale of U.K. Generation. There were no cash flows used for or provided by operating, investing or financing activities related to our discontinued operations for the nine months ended September 30, 2009 and 2008.

Benefit Plans

Benefit Plans
	9 Months Ended Sep. 30, 2009 USD / shares
Benefit Plans [Abstract]
Benefit Plans	Components of Net Periodic Benefit Cost The following tables provide the components of our net periodic benefit cost for the plans for the three and nine months ended September 30, 2009 and 2008: Other Postretirement Pension Plans Benefit Plans Three Months Ended September 30, Three Months Ended September 30, 2009 2008 2009 2008 (in millions) Service Cost $ 26 $ 25 $ 11 $ 10 Interest Cost 64 62 27 28 Expected Return on Plan Assets (80 ) (84 ) (21 ) (27 ) Amortization of Transition Obligation - - 7 7 Amortization of Net Actuarial Loss 14 10 11 3 Net Periodic Benefit Cost $ 24 $ 13 $ 35 $ 21 Other Postretirement Pension Plans Benefit Plans Nine Months Ended September 30, Nine Months Ended September 30, 2009 2008 2009 2008 (in millions) Service Cost $ 78 $ 75 $ 32 $ 31 Interest Cost 191 187 82 84 Expected Return on Plan Assets (241 ) (252 ) (61 ) (83 ) Amortization of Transition Obligation - - 20 21 Amortization of Net Actuarial Loss 44 29 32 8 Net Periodic Benefit Cost $ 72 $ 39 $ 105 $ 61

Business Segments

Business Segments
	9 Months Ended Sep. 30, 2009 USD / shares
Business Segments [Abstract]
Business Segments	As outlined in our 2008 Annual Report, our primary business is our electric utility operations.Within our Utility Operations 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.While our Utility Operations segment remains our primary business segment, other segments include our AEP River Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities primarily in the ERCOT market area.Intersegment sales and transfers are generally based on underlying contractual arrangements and agreements. Our reportable segments and their related business activities are as follows: Utility Operations Generation of electricity for sale to U.S. retail and wholesale customers. Electricity transmission and distribution in the U.S. AEP River Operations Commercial barging operations that annually transport approximately 33 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. Generation and Marketing Wind farms and marketing and risk management activities primarily in ERCOT. The remainder of our activities is presented as All Other.While not considered a business segment, All Other includes: Parents guarantee revenue received from affiliates, investment income, interest income and interest expense and other nonallocated costs. Forward natural gas contracts that were not sold with our natural gas pipeline and storage operations in 2004 and 2005.These contracts are financial derivatives which will gradually liquidate and completely expire in 2011. The first quarter 2008 cash settlement of a purchase power and sale agreement with TEM related to the Plaquemine Cogeneration Facility which was sold in 2006. Revenue sharing related to the Plaquemine Cogeneration Facility. The tables below present our reportable segment information for the three and nine months ended September 30, 2009 and 2008 and balance sheet information as of September 30, 2009 and December 31, 2008.These amounts include certain estimates and allocations where necessary. Nonutility Operations Utility Operations AEP River Operations Generation and Marketing All Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended September 30, 2009 Revenues from: External Customers $ 3,364 (d) $ 113 $ 68 $ 2 $ - $ 3,547 Other Operating Segments 25 (d) 4 - 1 (30) - Total Revenues $ 3,389 $ 117 $ 68 $ 3 $ (30) $ 3,547 Income (Loss) Before Discontinued Operations and Extraordinary Loss $ 448 $ 10 $ 5 $ (17) $ - $

Derivatives and Hedging

Derivatives and Hedging
	9 Months Ended Sep. 30, 2009 USD / shares
Derivatives, Hedging and Fair Value Measurements [Abstract]
Derivatives and Hedging	Objectives for Utilization of Derivative Instruments We are exposed to certain market risks as a major power producer and marketer of wholesale electricity, coal and emission allowances.These risks include commodity price risk, interest rate risk, credit risk and to a lesser extent foreign currency exchange risk.These risks represent the risk of loss that may impact us due to changes in the underlying market prices or rates.We manage these risks using derivative instruments. Strategies for Utilization of Derivative Instruments to Achieve Objectives Our strategy surrounding the use of derivative instruments focuses on managing our risk exposures, future cash flows and creating value based on our open trading positions by utilizing both economic and formal hedging strategies. To accomplish our objectives, we primarily employ risk management contracts including physical forward purchase and sale contracts, financial forward purchase and sale contracts and financial swap instruments.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 electricity, coal, natural gas, interest rate and to a lesser degree heating oil, gasoline, emission allowance 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 AEPs Board of Directors. The following table represents the gross notional volume of our outstanding derivative contracts as of September 30, 2009: Notional Volume of Derivative Instruments September 30, 2009 Unit of Primary Risk Exposure Volume Measure (in millions) Commodity: Power 544 MWHs Coal 61 Tons Natural Gas 153 MMBtu Heating Oil and Gasoline 8 Gallons Interest Rate $ 216 USD Interest Rate and Foreign Currency $ 89 USD Fair Value Hedging Strategies At certain times, we enter into interest rate derivative transactions in order to manage existing fixed interest rate risk exposure.These 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.Current

Fair Value Measurements

Fair Value Measurements
	9 Months Ended Sep. 30, 2009 USD / shares
Fair Value Measurements [Abstract]
Fair Value Measurements	With the adoption of new accounting guidance, we are required to provide certain fair value disclosures which we previously were only required to provide in our annual report.The new accounting guidance did not change the method to calculate the amounts reported on the Condensed Consolidated Balance Sheets. 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.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 at September 30, 2009 and December 31, 2008 are summarized in the following table: September 30, 2009 December 31, 2008 Book Value Fair Value Book Value Fair Value (in millions) Long-term Debt $ 17,253 $ 18,251 $ 15,983 $ 15,113 Fair Value Measurements of Other Temporary Investments Other Temporary Investments include marketable securities that we intend to hold for less than one year, investments by our protected cell captive insurance company and funds held by trustees primarily for the payment of debt. We classify our investments in marketable securities in accordance with the provisions of Investments Debt and Equity Securities accounting guidance.We do not have any investments classified as trading or held-to-maturity. Available-for-sale securities reflected in Other Temporary Investments are carried at fair value with the unrealized gain or loss, net of tax, reported in AOCI.Held-to-maturity securities, if any, reflected in Other Temporary Investments are carried at amortized cost.The cost of securities sold is based on specific identification or weighted average cost method.The fair value of most investment securities is determined by currently available market prices.Where quoted market prices are not available, we use the market price of similar types of securities that are traded in the market to estimate fair value. In evaluating potential impairment of equity securities with unrealized losses, we considered, among other criteria, the current fair value compared to cost, the length of time the security's fair value has been below cost, our intent and ability to retain the investment for a period of time sufficient to allow for any anticipated recovery in value and current economic conditions. The following is a summary of Other Temporary Investments: September 30, 2009 December 31, 2008 Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value Cost Gross Unrealized Gains Gross Unrealized Losses Estimated Fair Value Other Temporary Investments (in millions) Cash (a) $ 167 $ - $ - $ 167 $ 243 $ - $ - $ 243 Debt Securities 57 - - 57 56 - -

Income Taxes

Income Taxes
	9 Months Ended Sep. 30, 2009 USD / shares
Income Taxes [Abstract]
Income Taxes	We, along with our subsidiaries, file a consolidated federal income tax return.The allocation of the AEP Systems 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. We are no longer subject to U.S. federal examination for years before 2000.We have completed the exam for the years 2001 through 2006 and have issues that we are pursuing at the appeals level.The years 2007 and 2008 are currently under examination.Although the outcome of tax audits is uncertain, in managements opinion, adequate provisions for 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 have a material adverse effect on 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 and we are currently under examination in several state and local jurisdictions.We believe that we have filed tax returns with positions that may be challenged by these tax authorities.However, management does not believethat the ultimate resolution of these audits will materially impact net income.With few exceptions, we are no longer subject to state, local or non-U.S. income tax examinations by tax authorities for years before 2000. We are changing the tax method of accounting for the definition of a unit of property for generation assets.This change will provide a favorable cash flow benefit in 2009 and 2010. Federal Tax Legislation The American Recovery and Reinvestment Act of 2009 was signed into law by the President in February 2009.It provided for several new grant programs and expanded tax credits and an extension of the 50% bonus depreciation provision enacted in the Economic Stimulus Act of 2008.The enacted provisions are not expected to have a material impact on net income or financial condition.However, we forecast the bonus depreciation provision could provide a significant favorable cash flow benefit in 2009.

Financing Activities

Financing Activities
	9 Months Ended Sep. 30, 2009 USD / shares
Financing Activities [Abstract]
Financing Activities	Common Stock In April 2009, we issued 69 million shares of common stock at $24.50 per share for net proceeds of $1.64 billion, which were primarily used to repay cash drawn under our credit facilities in the second quarter of 2009. Long-term Debt September 30, December 31, Type of Debt 2009 2008 (in millions) Senior Unsecured Notes $ 12,316 $ 11,069 Pollution Control Bonds 2,055 1,946 Notes Payable 288 233 Securitization Bonds 1,995 2,132 Junior Subordinated Debentures 315 315 Spent Nuclear Fuel Obligation (a) 264 264 Other Long-term Debt 87 88 Unamortized Discount (net) (67 ) (64 ) Total Long-term Debt Outstanding 17,253 15,983 Less Portion Due Within One Year 1,540 447 Long-term Portion $ 15,713 $ 15,536 (a) Pursuant to the Nuclear Waste Policy Act of 1982, IM (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 of $306 million and $301 million at September 30, 2009 and December 31, 2008, respectively, are included in Spent Nuclear Fuel and Decommissioning Trusts on our Condensed Consolidated Balance Sheets. Long-term debt and other securities issued, retired and principal payments made during the first nine months of 2009 are shown in the tables below. Company Type of Debt Principal Amount Interest Rate Due Date (in millions) (%) Issuances: APCo Senior Unsecured Notes $ 350 7.95 2020 CSPCo Pollution Control Bonds 60 3.875 2038 CSPCo Pollution Control Bonds 32 5.80 2038 IM Senior Unsecured Notes 475 7.00 2019 IM Notes Payable 102 5.44 2013 IM Pollution Control Bonds 50 6.25 2025 IM Pollution Control Bonds 50 6.25 2025 OPCo Senior Unsecured Notes 500 5.375 2021 PSO Pollution Control Bonds 34 5.25 2014 Non-Registrant: AEP River Operations Notes Payable 49 7.59 2026 KPCo Senior Unsecured Notes 40 7.25 2021 KPCo Senior Unsecured Notes 30 8.03 2029 KPCo Senior Unsecured Notes 60 8.13 2039 TCC Pollution Control Bonds 101 6.30 2029 Total Issuances $ 1,933 (a) The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions. (a) Amount indicated on the statement of cash flows of $1,912 million is net of issuance costs and premium or discount. Company Type of Debt Principal Amount Paid Interest Rate Due Date (in millions) (%) Retirements and Principal Payments:

Document and Entity Information

Document and Entity Information (USD $)
	9 Months Ended Sep. 30, 2009	Oct. 28, 2009
Document and Entity Information [Abstract]
Entity Registrant Name	AMERICAN ELECTRIC POWER CO INC
Entity Central Index Key	0000004904
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock Shares Outstanding		477,658,465
Document Type	10-Q
Amendment Flag	false
Document Period End Date	2009-09-30