American Electric Power (AEP) 10-Q 4 Aug 09 2009 Q2 Quarterly report Financial data

1000 - Condensed Consolidated S

1000 - Condensed Consolidated Statements of Income (USD $)
In Millions, except Share data	3 Months Ended Jun. 30, 2009	3 Months Ended Jun. 30, 2008	6 Months Ended Jun. 30, 2009	6 Months Ended Jun. 30, 2008
Revenues
Utility Operations	$3,035	$3,200	$6,302	$6,210
Other Revenues	167	346	358	803
TOTAL REVENUES	3,202	3,546	6,660	7,013
Expenses
Fuel and Other Consumables Used for Electric Generation	764	1,053	1,693	2,033
Purchased Electricity for Resale	258	366	553	629
Other Operation and Maintenance	911	982	1,825	1,860
Gain on Sales of Assets, Net	(2)	(5)	(11)	(8)
Asset Impairments and Other Related Charges	0	0	0	(255)
Depreciation and Amortization	397	373	779	736
Taxes Other Than Income Taxes	192	191	389	389
TOTAL EXPENSES	2,520	2,960	5,228	5,384
OPERATING INCOME	682	586	1,432	1,629
Other Income (Expense):
Interest and Investment Income (Loss)	(5)	15	0	31
Carrying Costs Income	12	26	21	43
Allowance for Equity Funds Used During Construction	20	11	36	21
Interest Expense	(240)	(234)	(478)	(453)
INCOME BEFORE INCOME TAX EXPENSE AND EQUITY EARNINGS	469	404	1,011	1,271
Income Tax Expense	148	123	327	416
Equity Earnings of Unconsolidated Subsidiaries	1	0	1	2
INCOME BEFORE DISCONTINUED OPERATIONS AND EXTRAORDINARY LOSS	322	281	685	857
DISCONTINUED OPERATIONS, NET OF TAX	0	1	0	1
INCOME BEFORE EXTRAORDINARY LOSS	322	282	685	858
EXTRAORDINARY LOSS, NET OF TAX	(5)	0	(5)	0
NET INCOME	317	282	680	858
Less: Net Income Attributable to Noncontrolling Interests	1	1	3	3
NET INCOME ATTRIBUTABLE TO AEP SHAREHOLDERS	316	281	677	855
Less: Preferred Stock Dividend Requirements of Subsidiaries	0	0	1	1
EARNINGS ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	$316	$281	$676	$854
Earnings Per Share
WEIGHTED AVERAGE NUMBER OF BASIC AEP COMMON SHARES OUTSTANDING	472,220,041	401,513,958	439,703,968	401,155,975
BASIC EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Discontinued Operations and Extraordinary Loss	0.68	0.7	1.55	2.13
Discontinued Operations, Net of Tax	$0	$0	$0	$0
Income Before Extraordinary Loss	0.68	0.7	1.55	2.13
Extraordinary Loss, Net of Tax	-0.01	$0	-0.01	$0
TOTAL BASIC EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	0.67	0.7	1.54	2.13
WEIGHTED AVERAGE NUMBER OF DILUTED AEP COMMON SHARES OUTSTANDING	472,222,817	402,785,942	439,983,030	402,429,019
DILUTED EARNINGS (LOSS) PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS
Income Before Discontinued Operations and Extraordinary Loss	0.68	0.7	1.55	2.12
Discontinued Operations, Net of Tax	$0	$0	$0	$0
Income Before Extraordinary Loss	0.68	0.7	1.55	2.12
Extraordinary Loss, Net of Tax	-0.01	$0	-0.01	$0
TOTAL DILUTED EARNINGS PER SHARE ATTRIBUTABLE TO AEP COMMON SHAREHOLDERS	0.67	0.7	1.54	2.12
CASH DIVIDENDS PAID PER SHARE	0.41	0.41	0.82	0.82

2000 - Condensed Consolidated B

2000 - Condensed Consolidated Balance Sheet (USD $)
In Millions	6 Months Ended Jun. 30, 2009	12 Months Ended Dec. 31, 2008
Current Assets
Cash and Cash Equivalents	$358	$411
Other Temporary Investments	289	327
Accounts Receivable:
Customers	570	569
Accrued Unbilled Revenues	437	449
Miscellaneous	73	90
Allowance for Uncollectible Accounts	(43)	(42)
Total Accounts Receivable	1,037	1,066
Fuel	911	634
Materials and Supplies	575	539
Risk Management Assets	335	256
Regulatory Asset for Under-Recovered Fuel Costs	352	284
Margin Deposits	135	86
Prepayments and Other Current Assets	232	172
TOTAL CURRENT ASSETS	4,224	3,775
Property, Plant and Equipment, Electric:
Production	22,480	21,242
Transmission	8,084	7,938
Distribution	13,179	12,816
Other Property, Plant and Equipment (including coal mining and nuclear fuel)	3,810	3,741
Construction Work in Progress	3,145	3,973
Total Property, Plant and Equipment	50,698	49,710
Accumulated Depreciation and Amortization	17,139	16,723
TOTAL PROPERTY, PLANT AND EQUIPMENT - NET	33,559	32,987
Other Noncurrent Assets
Regulatory Assets	3,979	3,783
Securitized Transition Assets	1,983	2,040
Spent Nuclear Fuel and Decommissioning Trusts	1,268	1,260
[Goodwill]	76	76
Long-term Risk Management Assets	380	355
Deferred Charges and Other Noncurrent Assets	869	879
TOTAL OTHER NONCURRENT ASSETS	8,555	8,393
TOTAL ASSETS	46,338	45,155
Current Liabilities
Accounts Payable	1,096	1,297
Short-term Debt	562	1,976
Long-term Debt Due Within One Year	1,346	447
Risk Management Liabilities	158	134
Customer Deposits	271	254
Accrued Taxes	553	634
Accrued Interest	273	270
Regulatory Liability for Over-Recovered Fuel Costs	130	66
Other Current Liabilities	1,004	1,219
TOTAL CURRENT LIABILITIES	5,393	6,297
Noncurrent Liabilities
Long-term Debt	15,350	15,536
Long-term Risk Management Liabilities	138	170
Deferred Income Taxes	5,417	5,128
Regulatory Liabilities and Deferred Investment Tax Credits	2,746	2,789
Asset Retirement Obligations	1,181	1,154
Employee Benefits and Pension Obligations	2,169	2,184
Deferred Credits and Other Noncurrent Liabilities	1,120	1,126
TOTAL NONCURRENT LIABILITIES	28,121	28,087
TOTAL LIABILITIES	33,514	34,384
Cumulative Preferred Stock Not Subject to Mandatory Redemption	61	61
Commitments and Contingencies (Note 4)	-	-
Equity
Common Stock Par Value $6.50:	3,231	2,771
Paid-in Capital	5,755	4,527
Retained Earnings	4,160	3,847
Accumulated Other Comprehensive Income (Loss)	(401)	(452)
TOTAL AEP COMMON SHAREHOLDERS' EQUITY	12,745	10,693
Noncontrolling Interests	18	17
TOTAL EQUITY	12,763	10,710
TOTAL LIABILITIES AND EQUITY	$46,338	$45,155

2100 - Parenthetical Informatio

2100 - Parenthetical Information for Condensed Consolidated Balance Sheet (USD $)
	Jun. 30, 2009	Dec. 31, 2008
Balance Sheet Parenthetical
Common Stock, Par Value Per Share	6.5	6.5
Common Stock, Shares Authorized	600,000,000	600,000,000
Common Stock, Shares, Issued	497,033,402	426,321,248
Treasury Stock, Shares	20,249,992	20,249,992

3000 - Condensed Consolidated S

3000 - Condensed Consolidated Statements of Cash Flow (USD $)
In Millions	6 Months Ended Jun. 30, 2009	6 Months Ended Jun. 30, 2008
Operating Activites
Net Income	$680	$858
Less: Discontinued Operations, Net of Tax	0	(1)
Income Before Discontinued Operations	680	857
Adjustments to Reconcile Net Income to Net Cash Flows from Operating Activities:
Depreciation and Amortization	779	736
Deferred Income Taxes	360	316
Extraordinary Loss, Net of Tax	5	0
Carrying Costs Income	(21)	(43)
Allowance for Equity Funds Used During Construction	(36)	(21)
Mark-to-Market of Risk Management Contracts	(83)	66
Amortization of Nuclear Fuel	25	45
Deferred Property Taxes	38	36
Fuel Over/Under-Recovery, Net	(246)	(245)
Gain on Sales of Assets, Net	(11)	(8)
Change in Other Noncurrent Assets	0	(195)
Change in Other Noncurrent Liabilities	84	(90)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net	29	(123)
Fuel, Materials and Supplies	(313)	(82)
Margin Deposits	(49)	(16)
Accounts Payable	18	188
Customer Deposits	17	18
Accrued Taxes, Net	(110)	(61)
Accrued Interest	3	16
Other Current Assets	(25)	(13)
Other Current Liabilities	(287)	(180)
Net Cash Flows from Operating Activities	857	1,201
Investing Activities
Construction Expenditures	(1,547)	(1,608)
Change in Other Temporary Investments, Net	43	48
Purchases of Investment Securities	(443)	(635)
Sales of Investment Securities	411	666
Acquisitions of Nuclear Fuel	(152)	(99)
Acquisitions of Assets	(11)	(81)
Proceeds from Sales of Assets	240	69
Other Investing Activities	(19)	(5)
Net Cash Flows Used for Investing Activities	(1,478)	(1,645)
Financing Activities
Issuance of Common Stock, Net	1,688	72
Change in Short-term Debt, Net	(1,414)	45
Issuance of Long-term Debt	1,075	2,204
Retirement of Long-term Debt	(372)	(1,472)
Principal Payments for Capital Lease Obligations	(42)	(48)
Dividends Paid on Common Stock	(364)	(333)
Dividends Paid on Cumulative Preferred Stock	(1)	(1)
Other Financing Activities	(2)	17
Net Cash Flows from Financing Activities	568	484
Net Increase (Decrease) in Cash and Cash Equivalents	(53)	40
Cash and Cash Equivalents at Beginning of Period	411	178
Cash and Cash Equivalents at End of Period	358	218
Supplementary Information
Cash Paid for Interest, Net of Capitalized Amounts	495	412
Net Cash Paid for Income Taxes	27	131
Noncash Acquisitions Under Capital Leases	17	35
Noncash Acquisition of Land/Mineral Rights	0	42
Construction Expenditures Included in Accounts Payable at June 30,	$270	$328

4000 - Condensed Consolidated S

4000 - Condensed Consolidated Statements of Change in Equity and Comprehensive Income (Loss) (USD $)
In Millions	6 Months Ended Jun. 30, 2009	6 Months Ended Jun. 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	1,738	72
Common Stock Dividends	(366)	(333)
Preferred Stock Dividends	(1)	(1)
Other Changes in Equity	(49)	3
Subtotal - Equity	12,032	9,827
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax	17	(34)
Securities Available for Sale, Net of Tax	9	(7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	25	6
Net Income	680	858
Total Comprehensive Income	731	823
Ending Balance	12,763	10,650
Shares Issued, Ending Balance	497
Common Stock
Beginning Balance	2,771	2,743
Shares Issued, Beginning Balance	426	422
Issuance of Common Stock, Value	460	11
Issuance of Common Stock, Shares	71	2
Other Comprehensive Income (Loss), Net of Taxes:
Ending Balance	3,231	2,754
Shares Issued, Ending Balance	497	424
Additional Paid-in Capital
Beginning Balance	4,527	4,352
Issuance of Common Stock, Value	1,278	61
Other Changes in Equity	(50)	2
Other Comprehensive Income (Loss), Net of Taxes:
Ending Balance	5,755	4,415
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	(363)	(330)
Preferred Stock Dividends	(1)	(1)
Other Comprehensive Income (Loss), Net of Taxes:
Net Income	677	855
Ending Balance	4,160	3,651
Accumulated Other Comprehensive Income
Beginning Balance	(452)	(154)
Other Comprehensive Income (Loss), Net of Taxes:
Cash Flow Hedges, Net of Tax	17	(34)
Securities Available for Sale, Net of Tax	9	(7)
Amortization of Pension and OPEB Deferred Costs, Net of Tax	25	6
Ending Balance	(401)	(189)
Noncontrolling Interest
Beginning Balance	17	18
Common Stock Dividends	(3)	(3)
Other Changes in Equity	1	1
Other Comprehensive Income (Loss), Net of Taxes:
Net Income	3	3
Ending Balance	$18	$19

4100 - Parenthetical Informatio

4100 - Parenthetical Information for Condensed Consolidate Statements of Changes in Common Shareholders' Equity and Comprehensive Income (Loss) (USD $)
In Millions	6 Months Ended Jun. 30, 2009	6 Months Ended Jun. 30, 2008
Equity Parenthetical
EITF 06-10 Adoption, Tax		$6
SFAS 157 Adoption, Tax		0
Cash Flow Hedges, Tax	9	19
Securities Available for Sale, Tax	5	4
Amortization of Pension and OPEB Deferred Costs, Tax	$14	$3

6000 - Significant Accounting M

6000 - Significant Accounting Matters
	6 Months Ended Jun. 30, 2009 USD / shares
Summary of Significant Accounting Policies
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 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, 2009 are 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 August 4, 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 Annual Report on Form 10-K for the year ended December 31, 2008 as filed with the SEC on February 27, 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 June 30, 2009 2008 (in millions, except per share data) $/share $/share Earnings Applicable to AEP Common Shareholders $ 316 $ 281 Weighted Average Number of Basic Shares Outstanding 472.2 $ 0.67 401.5 $ 0.70 Weighted Average Dilutive Effect of: Performance Share Units - - 0.9 - Stock Options - - 0.2 - Restricted Stock Units - - 0.1 - Restricted Shares - - 0.1 - Weighted Average Number of Diluted Shares Outstanding 472.2 $ 0.67 402.8 $ 0.70 Six Months Ended June 30, 2009 2008 (in millions, except per share data) $/share $/share Earnings Applicable to AEP Common Shareholders $ 676 $ 854 Weighted Average Number of Basic Shares Outstanding 439.7 $ 1.54 401.2 $ 2.13 Weighted Average Dilutive Effect of: Performance Share Units 0.3 - 0.8 (0.01 ) Stock Options - - 0.2 - Restricted Stock Units - - 0.1 - Restricted Shares - - 0.1 - Weighted Average Number of Diluted Shares Outstanding 440.0 $ 1.54 402.4 $ 2.12 The assumed conversion of our share-based compensation does not affect net earnings for purposes of calculating diluted earnings per share. Options to purchase 1,123,869 and 146,900 shares of common stock were outstanding at June 30, 2009 and 2008, respectively, but were not included in the computation of diluted earnings per share because the option

6010 - New Accounting Pronounce

6010 - New Accounting Pronouncements and Extraordinary Item
	6 Months Ended Jun. 30, 2009 USD / shares
New Accounting Pronouncements
NEW ACCOUNTING PRONOUNCEMENTS	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 six 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 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 applied the standard to prior periods.The retrospective application of this

6020 - Rate Matters

6020 - Rate Matters
	6 Months Ended Jun. 30, 2009 USD / shares
Rate Matters
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 July 2008, as required by the 2008 amendments to the Ohio restructuring legislation, CSPCo and OPCo filed ESPs with the PUCO to establish standard service offer rates.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.The ESPs will be in effect through 2011.The ESP order authorized increases to revenues during the ESP period and capped the overall revenue increases through a phase-in of the FAC.The capped increases for CSPCo are 7% in 2009, 6% in 2010 and 6% in 2011 and for OPCo are 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 meet 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 ESP period will be recovered through a non-bypassable surcharge over the period 2012 through 2018. As of June 30, 2009, the recognized revenues and the FAC deferrals were adjusted to reflect the PUCOs July 2009 rehearing entry, which among other things, reversed the prior authorization to recover the cost of CSPCo's 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 FAC deferrals after adjustments at June 30, 2009 were $34 million and $140 million for CSPCo and OPCo, respectively, including carrying charges.The PUCO 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 PUCO also addressed several additional matters 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

6030 - Commitments, Guarantees

6030 - Commitments, Guarantees and Contingencies
	6 Months Ended Jun. 30, 2009 USD / shares
Commitments Guarantees and Contigencies
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 recorded for guarantees in accordance with FIN 45 Guarantors Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.In addition, we adopted FSP SFAS 133-1 and FIN 45-4 Disclosures about Credit Derivatives and Certain Guarantees:An amendment of FASB Statement No. 133 and FASB Interpretation No. 45; and Clarification of the Effective Date of FASB Statement No. 161 effective December 31, 2008.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 June 30, 2009, the maximum future payments for all the LOCs issued under the two $1.5 billion credit facilities are approximately $113 million with maturities ranging from July 2009 to July 2010. We have a $627 million 3-year credit agreement.As of June 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), an entity consolidated under FIN 46R.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 June 30, 2009, SWEPCo has collected approximately $40 million through a rider for final mine closure and reclama

6040 - Acquisitions and Disposi

6040 - Acquisitions and Disposition
	6 Months Ended Jun. 30, 2009 USD / shares
Acquisitions and Dispositions
ACQUISITIONS AND DISCONTINUED OPERATIONS	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 Dolet Hills Lignite Company, LLC 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 LLC 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 which will diversify 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 in 2009 and 2008 related to discontinued operations: U.K. Generation (a) Three Months Ended June 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 U.K. Generation (a) Six Months Ended June 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 six months ended June 30, 2009 and 2008.

6050 - Benefit Plans

6050 - Benefit Plans
	6 Months Ended Jun. 30, 2009 USD / shares
Benefit Plans
BENEFIT PLANS	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 six months ended June 30, 2009 and 2008: Other Postretirement Pension Plans Benefit Plans Three Months Ended June 30, Three Months Ended June 30, 2009 2008 2009 2008 (in millions) Service Cost $ 26 $ 25 $ 11 $ 11 Interest Cost 64 62 28 28 Expected Return on Plan Assets (81 ) (84 ) (20 ) (28 ) Amortization of Transition Obligation - - 6 7 Amortization of Net Actuarial Loss 15 10 10 2 Net Periodic Benefit Cost $ 24 $ 13 $ 35 $ 20 Other Postretirement Pension Plans Benefit Plans Six Months Ended June 30, Six Months Ended June 30, 2009 2008 2009 2008 (in millions) Service Cost $ 52 $ 50 $ 21 $ 21 Interest Cost 127 125 55 56 Expected Return on Plan Assets (161 ) (168 ) (40 ) (56 ) Amortization of Transition Obligation - - 13 14 Amortization of Net Actuarial Loss 30 19 21 5 Net Periodic Benefit Cost $ 48 $ 26 $ 70 $ 40

6060 - Business Segments

6060 - Business Segments
	6 Months Ended Jun. 30, 2009 USD / shares
Business Segments
BUSINESS SEGMENTS	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 six months ended June 30, 2009 and 2008 and balance sheet information as of June 30, 2009 and December 31, 2008.These amounts include certain estimates and allocations where necessary. Nonutility Operations Utility Operations AEPRiver Operations Generation and Marketing All Other (a) Reconciling Adjustments Consolidated (in millions) Three Months Ended June 30, 2009 Revenues from: External Customers $ 3,035 (d) $ 105 $ 58 $ 4 $ - $ 3,202 Other Operating Segments 21 (d) 3 1 5 (30) - Total Revenues $ 3,056 $ 108 $ 59 $ 9 $ (30) $ 3,202 Income (Loss) Before Discontinued Operations and Extraordinary Loss $ 327 $ 1 $ 4 $ (10) $ - $ 322 Extraordinary Loss, Net of Tax (5) -

6070 - Derivatives and Hedging

6070 - Derivatives and Hedging
	6 Months Ended Jun. 30, 2009 USD / shares
Derivatives, Hedging and Fair Value Measurements
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 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 risk 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 SFAS 133 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 SFAS 133.Derivative risk management contracts elected normal under the normal purchases and normal sales scope exception are not subject to the requirements of SFAS 133. 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 June 30, 2009: Notional Volume of Derivative Instruments June 30, 2009 Unit of Primary Risk Exposure Volume Measure (in millions) Commodity: Power 590 MWHs Coal 56 Tons Natural Gas 192 MMBtu Heating Oil and Gasoline 8 Gallons Interest Rate $ 421 USD Interest Rate and Foreign Currency $ 497 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.Currently, this strategy is not actively employed. Cash Flow Hedgi

6080 - Fair Value Measurements

6080 - Fair Value Measurements
	6 Months Ended Jun. 30, 2009 USD / shares
Fair Value Measurements
FAIR VALUE MEASUREMENTS	FAIR VALUE MEASUREMENTS With the adoption of three new accounting standards, we are required to provide certain fair value disclosures which we previously were only required to provide in our annual report.The new standards 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 June 30, 2009 and December 31, 2008 are summarized in the following table: June 30, 2009 December 31, 2008 Book Value Fair Value Book Value Fair Value (in millions) Long-term Debt $ 16,696 $ 16,600 $ 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 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 SFAS 115, Accounting for Certain Investments in Debt and Equity Securities (SFAS 115).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: June 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) $ 199 $ - $ - $ 199 $ 243 $ - $ - $ 243 Debt Securities 56 - - 56 56 - - 56 Equity Securities 18 16 - 3

6090 -Income Taxes

6090 -Income Taxes
	6 Months Ended Jun. 30, 2009 USD / shares
Income Taxes
INCOME TAXES	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.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. 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.

6100 - Financing Activities

6100 - Financing Activities
	6 Months Ended Jun. 30, 2009 USD / shares
Financing Activities
FINANCING ACTIVITIES	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 was primarily used to repay cash drawn under our credit facilities in the second quarter of 2009. Long-term Debt June 30, December 31, Type of Debt 2009 2008 (in millions) Senior Unsecured Notes $ 11,820 $ 11,069 Pollution Control Bonds 2,080 1,946 Notes Payable 146 233 Securitization Bonds 2,051 2,132 Junior Subordinated Debentures 315 315 Spent Nuclear Fuel Obligation (a) 264 264 Other Long-term Debt 88 88 Unamortized Discount (net) (68 ) (64 ) Total Long-term Debt Outstanding 16,696 15,983 Less Portion Due Within One Year 1,346 447 Long-term Portion $ 15,350 $ 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 $304 million and $301 million at June 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 six 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 IM Senior Unsecured Notes 475 7.00 2019 IM Pollution Control Bonds 50 6.25 2025 IM Pollution Control Bonds 50 6.25 2025 PSO Pollution Control Bonds 34 5.25 2014 Non-Registrant: KPCo Senior Unsecured Notes 40 7.25 2021 KPCo Senior Unsecured Notes 30 8.03 2029 KPCo Senior Unsecured Notes 60 8.13 2039 Total Issuances $ 1,089 (a) The above borrowing arrangements do not contain guarantees, collateral or dividend restrictions. (a) Amount indicated on statement of cash flows of $1,075 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: APCo Senior Unsecured Notes $ 150 6.60 2009 OPCo Notes Payable 1 6.27 2009 OPCo Notes Payable 7 7.21 2009 OPCo Notes Payable 70 7.49 2009 PSO Senior Unsecured Notes 50 4.70 2009 SWEPCo Notes Payable 2 4.47 2011 Non-Registrant: AEP Subsidiaries Notes Payable 3 Variable 2017 AEP Subsidiaries Notes Payable 4 5.88 2011 AEGCo Seni

9011 - Document and Entity Info

9011 - Document and Entity Information (USD $)
	6 Months Ended Jun. 30, 2009
Document and Entity Information
Entity Registrant Name	American Electric Power Company, Inc.
Entity Central Index Key	0000004904
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float	$16,336,246,629
Entity Common Stock, Shares Outstanding	476,790,811
Document Type	10-Q
Amendment Flag	false
Amendment Description	n/a
Document Period End Date	2009-06-30