American Electric Power (AEP) 8-K/A 23 Jan 09 Financial Statements and Exhibits Financial data

Statement of Financial Position

Statement of Financial Position, Classified (USD $)
In Millions, except Share data	Dec. 31, 2007	Dec. 31, 2006
Assets, Current [Abstract]
Cash and Cash Equivalents	$178	$301
Other Temporary Investments	365	425
Accounts Receivable, Net, Current [Abstract]
Accounts Receivable - Customers	730	676
Accounts Receivable - Accrued Unbilled Revenues	379	350
Accounts Receivable - Miscellaneous	60	44
Allowance for Uncollectible Accounts	(52)	(30)
Total Accounts Receivable	1,117	1,040
Fuel, Materials and Supplies	967	913
Risk Management Assets	286	680
Margin Deposits	58	120
Prepayments and Other	81	109
Assets, Current, Total	3,052	3,588
Property, Plant and Equipment, Gross [Abstract]
Property, Plant and Equipment, Electric, Production	20,233	16,787
Property, Plant and Equipment, Electric, Transmission	7,392	7,018
Property, Plant and Equipment, Electric, Distribution	12,056	11,338
Property, Plant and Equipment, Other (including coal mining and nuclear fuel)	3,445	3,405
Construction Work in Progress	3,019	3,473
Property, Plant and Equipment, Gross, Total	46,145	42,021
Accumulated Depreciation and Amortization	16,275	15,240
Property, Plant and Equipment, Net, Total	29,870	26,781
Regulatory Assets	2,199	2,477
Securitized Transition Assets	2,108	2,158
Spent Nuclear Fuel and Decommissioning Trusts	1,347	1,248
Goodwill	76	76
Long-term Risk Management Assets	340	378
Employee Benefits and Pension Assets	486	327
Deferred Charges and Other	888	910
Assets, Noncurrent, Total	7,444	7,574
Assets Held for Sale	0	44
Assets, Total	40,366	37,987
Liabilities, Current [Abstract]
Accounts Payable	1,324	1,360
Short-term Debt	660	18
Long-term Debt Due Within One Year	792	1,269
Risk Management Liabilities	250	541
Customer Deposits	337	339
Accrued Taxes	601	781
Accrued Interest	235	186
Other Liabilities, Current	1,008	962
Liabilities, Current	5,207	5,456
Liabilities, Noncurrent [Abstract]
Long-term Debt	14,202	12,429
Long-term Risk Management Liabilities	189	260
Deferred Income Taxes	4,730	4,690
Regulatory Liabilities and Deferred Investment Tax Credits	2,952	2,910
Asset Retirement Obligations	1,075	1,023
Employee Benefits and Pension Obligations	712	823
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2	139	148
Deferred Credits and Other	1,020	775
Liabilities, Noncurrent, Total	25,019	23,058
Liabilities, Total	30,226	28,514
Cumulative Preferred Stock Not Subject to Mandatory Redemption	61	61
Stockholders' Equity [Abstract]
Common Stock	2,743	2,718
Paid in Capital	4,352	4,221
Retained Earnings	3,138	2,696
Accumulated Other Comprehensive Income (Loss)	(154)	(223)
Stockholders' Equity, Total	10,079	9,412
Liabilities and Stockholders' Equity, Total	$40,366	$37,987
Common Stock, Par Value Per Share	6.5	6.5
Common Stock, Shares Authorized	600,000,000	600,000,000
Common Stock, Shares, Issued	421,926,696	418,174,728
Treasury Stock, Shares	21,499,992	21,499,992

Statement of Income (Excluding

Statement of Income (Excluding Gross Margin Alternative) (USD $)
In Millions, except Share data	12 Months Ended Dec. 31, 2007	12 Months Ended Dec. 31, 2006	12 Months Ended Dec. 31, 2005
Revenues [Abstract]
Utility Operations	$12,101	$12,066	$11,157
Other	1,279	556	954
Revenues, Total	13,380	12,622	12,111
Operating Expenses [Abstract]
Fuel and Other Consumables Used for Electric Generation	3,829	3,817	3,592
Purchased Energy and Gas for Resale	1,138	856	943
Other Operation and Maintenance	3,867	3,639	3,619
Gain on Disposition of Assets, Net	(41)	(69)	(120)
Asset Impairments and Other Related Charges	0	209	39
Depreciation and Amortization	1,513	1,467	1,348
Taxes Other Than Income Taxes	755	737	763
Operating Expenses, Total	11,061	10,656	10,184
Operating Income	2,319	1,966	1,927
Interest and Investment Income	51	99	105
Carrying Costs Income	51	114	55
Gain on Disposition of Equity Investments, Net	47	3	56
Investment Value Losses	0	0	(7)
Allowance for Equity Funds Used During Construction	33	30	21
Interest And Preferred Stock Dividend Requirements
Interest Expense	841	732	697
Preferred Stock Dividend Requirements of Subsidiaries	3	3	7
Interest and Preferred Stock Dividend Requirements, Total	844	735	704
Income Before Income Tax Expense, Minority Interest Expense and Equity Earnings	1,657	1,477	1,453
Income Tax Expense	516	485	430
Minority Interest Expense	3	3	4
Equity Earnings of Unconsolidated Subsidiaries	6	3	10
Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change	1,144	992	1,029
Discontinued Operations, Net of Tax	24	10	27
Income before Extraordinary Loss and Cumulative Effect of Accounting Change	1,168	1,002	1,056
Extraordinary Loss, Net of Tax	(79)	0	(225)
Cumulative Effect of Accounting Change, Net of Tax	0	0	(17)
Net Income	$1,089	$1,002	$814
Earnings Per Share, Basic [Abstract]
Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change, Per Basic Share	2.87	2.52	2.64
Discontinued Operations, Net of Tax, Per Basic Share	0.06	0.02	0.07
Income before Extraordinary Loss and Cumulative Effect of Accounting Change, Per Basic Share	2.93	2.54	2.71
Extraordinary Loss, Net of Tax, Per Basic Share	-0.2	$0	-0.58
Cumulative Effect of Accounting Change, Net of Tax, Per Basic Share	$0	$0	-0.04
Earnings Per Share, Basic, Total	2.73	2.54	2.09
Weighted Average Number of Basic Shares Outstanding	398,784,745	394,219,523	389,969,636
Earnings Per Share, Diluted [Abstract]
Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change, Per Diluted Share	2.86	2.5	2.63
Discontinued Operations, Net of Tax, Per Diluted Share	0.06	0.03	0.07
Income before Extraordinary Loss and Cumulative Effect of Accounting Change, Per Diluted Share	2.92	2.53	2.7
Extraordinary Loss, Net of Tax, Per Diluted Share	-0.2	$0	-0.58
Cumulative Effect of Accounting Change, Net of Tax, Per Diluted Share	$0	$0	-0.04
Earnings Per Share, Diluted, Total	2.72	2.53	2.08
Weighted Average Number of Diluted Shares Outstanding	400,198,799	396,483,464	391,423,842
Cash Dividends Paid Per Share	1.58	1.5	1.42

Statement of Shareholders' Equi

Statement of Shareholders' Equity and Other Comprehensive Income (USD $)
In Millions, except Share data	Common Stock at Par Value [Member]	Common Stock [Member]	Additional Paid-in Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Income [Member]	Total
Shares, Issued, Beginning Balance at Dec. 31, 2004		405,000,000
Stockholders' Equity, Beginning Balance at Dec. 31, 2004	$2,632		$4,203	$2,024	($344)	$8,515
Issuance of Common Stock, Value	67		335			402
Issuance of Common Stock, Shares		10,000,000
Paid-in Capital, Other			20			20
Dividends, Common Stock				(553)		(553)
Repurchase of Common Stock			(427)			(427)
FIN 48 Adoption, Net of Tax				0		0
SFAS 158 Adoption Costs Established as a Regulatory Asset for the Reapplication of SFAS 71, Net of Tax					0	0
Securities Available for Sale, Net of Tax					20	20
Cash Flow Hedges, Net of Tax					(27)	(27)
Foreign Currency Translation Adjustments, Net of Tax					(6)	(6)
Minimum Pension Liability, Net of Tax					330	330
Pension and OPEB Funded Status, Net of Tax					0	0
Net Income				814		814
Minimum Pension Liability Elimination, Net of Tax					0	0
SFAS 158 Adoption, Net of Tax					0	0
SFAS 158 Adoption, Tax					0
SFAS 158 Adoption Costs Established as a Regulatory Asset for the Reapplication of SFAS 71, Tax					0
Securities Available for Sale, Tax					11
Cash Flow Hedges, Tax					15
Foreign Currency Translation Adjustment, Tax					0
Minimum Pension Liability, Tax					175
Pension and OPEB Funded Status, Tax					0
Minimum Pension Liability Elimination, Tax Effect					0
Shares, Issued, Ending Balance at Dec. 31, 2005		415,000,000
Stockholders' Equity, Ending Balance at Dec. 31, 2005	2,699		4,131	2,285	(27)	9,088
Issuance of Common Stock, Value	19		80			99
Issuance of Common Stock, Shares		3,000,000
Paid-in Capital, Other			10			10
Dividends, Common Stock				(591)		(591)
Repurchase of Common Stock			0			0
FIN 48 Adoption, Net of Tax				0		0
SFAS 158 Adoption Costs Established as a Regulatory Asset for the Reapplication of SFAS 71, Net of Tax					0	0
Securities Available for Sale, Net of Tax					(1)	(1)
Cash Flow Hedges, Net of Tax					21	21
Foreign Currency Translation Adjustments, Net of Tax					0	0
Minimum Pension Liability, Net of Tax					2	2
Pension and OPEB Funded Status, Net of Tax					0	0
Net Income				1,002		1,002
Minimum Pension Liability Elimination, Net of Tax					17	17
SFAS 158 Adoption, Net of Tax					(235)	(235)
SFAS 158 Adoption, Tax					126
SFAS 158 Adoption Costs Established as a Regulatory Asset for the Reapplication of SFAS 71, Tax					0
Securities Available for Sale, Tax					0
Cash Flow Hedges, Tax					11
Foreign Currency Translation Adjustment, Tax					0
Minimum Pension Liability, Tax					1
Pension and OPEB Funded Status, Tax					0
Minimum Pension Liability Elimination, Tax Effect					9
Shares, Issued, Ending Balance at Dec. 31, 2006		418,000,000
Stockholders' Equity, Ending Balance at Dec. 31, 2006	2,718		4,221	2,696	(223)	9,412
Issuance of Common Stock, Value	25		119			144
Issuance of Common Stock, Shares		4,000,000
Paid-in Capital, Other			12			12
Dividends, Common Stock				(630)		(630)
Repurchase of Common Stock			0			0
FIN 48 Adoption, Net of Tax				(17)		(17)
SFAS 158 Adoption Costs Established as a Regulatory Asset for the Reapplication of SFAS 71, Net of Tax					11	11
Securities Available for Sale, Net of Tax					(1)	(1)
Cash Flow Hedges, Net of Tax					(20)	(20)
Foreign Currency Translation Adjustments, Net of Tax					0	0
Minimum Pension Liability, Net of Tax					0	0
Pension and OPEB Funded Status, Net of Tax					79	79
Net Income				1,089		1,089
Minimum Pension Liability Elimination, Net of Tax					0	0
SFAS 158 Adoption, Net of Tax					0	0
SFAS 158 Adoption, Tax					0
SFAS 158 Adoption Costs Established as a Regulatory Asset for the Reapplication of SFAS 71, Tax					6
Securities Available for Sale, Tax					1
Cash Flow Hedges, Tax					10
Foreign Currency Translation Adjustment, Tax					0
Minimum Pension Liability, Tax					0
Pension and OPEB Funded Status, Tax					42
Minimum Pension Liability Elimination, Tax Effect					0
Shares, Issued, Ending Balance at Dec. 31, 2007		422,000,000
Stockholders' Equity, Ending Balance at Dec. 31, 2007	$2,743		$4,352	$3,138	($154)	$10,079

Statement of Cash Flows

Statement of Cash Flows (USD $)
In Millions	12 Months Ended Dec. 31, 2007	12 Months Ended Dec. 31, 2006	12 Months Ended Dec. 31, 2005
Net Cash Provided by (Used in) Operating Activities [Abstract]
Net Income	$1,089	$1,002	$814
Less: Discontinued Operations, Net of Tax	(24)	(10)	(27)
Income Before Discontinued Operations	1,065	992	787
Adjustments to Reconcile Income (Loss) to Net Cash Provided by (Used in) Continuing Operations [Abstract]
Depreciation and Amortization	1,513	1,467	1,348
Deferred Income Taxes	76	24	65
Deferred Investment Tax Credits	(24)	(29)	(32)
Cumulative Effect of Accounting Change, Net of Tax	0	0	17
Extraordinary Loss, Net of Tax	79	0	225
Asset Impairments, Investment Value Losses and Other Related Charges	0	209	46
Carrying Costs Income	(51)	(114)	(55)
Allowance for Equity Funds Used During Construction	(33)	(30)	(21)
Mark-to-Market of Risk Management Contracts	42	(37)	84
Amortization of Nuclear Fuel	65	50	56
Pension Contributions to Qualified Plan Trusts	0	0	(626)
Deferred Property Taxes	(26)	(14)	(17)
Fuel Over/Under-Recovery, Net	(117)	182	(239)
Gain on Sales of Assets and Equity Investments, Net	(88)	(72)	(176)
Change in Noncurrent Liability for NSR Settlement	58	0	0
Change in Other Noncurrent Assets	(98)	15	(94)
Change in Other Noncurrent Liabilities	90	28	67
Accounts Receivable, Net	(113)	177	(7)
Fuel, Materials and Supplies	16	(187)	(20)
Margin Deposits	62	101	(108)
Accounts Payable	(21)	56	140
Customer Deposits	(2)	(232)	157
Accrued Taxes	(90)	128	48
Other Current Assets	(11)	17	52
Other Current Liabilities	(4)	1	180
Net Cash Flows from Operating Activities	2,388	2,732	1,877
Net Cash Provided by (Used in) Investing Activities [Abstract]
Construction Expenditures	(3,556)	(3,528)	(2,404)
Change in Other Temporary Investments, Net	(114)	(33)	76
Purchases of Investment Securities	(11,086)	(18,359)	(8,836)
Sales of Investment Securities	11,213	18,080	8,934
Acquisitions of Assets	(512)	0	(360)
Proceeds from Sale of Assets	222	186	1,606
Other Investing Activities	(88)	(89)	(21)
Net Cash Flows Used for Investing Activities	(3,921)	(3,743)	(1,005)
Net Cash Provided by (Used in) Financing Activities [Abstract]
Issuance of Common Stock	144	99	402
Repurchase of Common Stock	0	0	(427)
Issuance of Long-term Debt	2,546	3,359	2,651
Retirement of Long-term Debt, Total	(1,286)	(1,946)	(2,729)
Change in Short-term Debt, Net	642	7	(13)
Proceeds from Nuclear Fuel Sale/Leaseback	85	0	0
Principal Payments for Capital Lease Obligations	(67)	(63)	(56)
Dividends Paid on Common Stock	(630)	(591)	(553)
Other Financing Activities	(24)	46	(66)
Net Cash Flows from (Used for) Financing Activities	1,410	911	(791)
Net Increase (Decrease) in Cash and Cash Equivalents	(123)	(100)	81
Cash and Cash Equivalents at Beginning of Period	301	401	320
Cash and Cash Equivalents at End of Period	$178	$301	$401

Document Information

Document Information
	12 Months Ended Dec. 31, 2007 USD / shares
Document Information [Line Items]
Document Type	10-K
Amendment Flag	false
Amendment Description	none
Document Period End Date	2007-12-31

Entity Information

Entity Information (USD $)
	12 Months Ended Dec. 31, 2007
Entity Information [Line Items]
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	$17,979,507,421
Entity Common Stock, Shares Outstanding	400,426,704

Notes to Financial Statements

Notes to Financial Statements
	12 Months Ended Dec. 31, 2007 USD / shares
Notes to Financial Statements
Organization	ORGANIZATION The principal business conducted by nine of our electric utility operating companies is the generation, transmission and distribution of electric power. Pursuant to the Texas Restructuring Legislation, TCC and TNC have completed the final stage of exiting the generation business and along with WPCo and KGPCo provide only transmission and distribution services. AEGCo is a regulated electricity generation business whose function is to provide power to our regulated electric utility operating companies. These companies are subject to regulation by the FERC under the Federal Power Act and the Energy Policy Act of 2005. These companies maintain accounts in accordance with the FERC and other regulatory guidelines. These companies are subject to further regulation with regard to rates and other matters by state regulatory commissions. We also engage in wholesale electricity, natural gas and other commodity marketing and risk management activities in the United States. In addition, our operations include nonregulated wind farms, coal mining and barging operations and we provide various energy-related services.
Significant Accounting Policies [Text Block]	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Rates and Service Regulation All of our affiliated transactions are regulated by the FERC under the 2005 Public Utility Holding Company Act (2005 PUHCA), including intercompany activity with our service company, AEPSC. Our public utility subsidiaries' rates are regulated by the FERC and state regulatory commissions in our eleven state operating territories. The state regulatory commissions with jurisdiction approve the retail rates charged and regulate the retail services and operations of the utility subsidiaries for the generation and supply of power, a majority of transmission energy delivery services and distribution services. The FERC regulates wholesale power markets and wholesale power transactions. Our wholesale power transactions are generally market-based and are not cost-based regulated unless we negotiate and file a cost-based contract with the FERC or the FERC determines that we have "market power" in the region in which the transaction is taking place. We enter into wholesale all-requirements power supply contracts with various municipalities and cooperatives that are FERC-regulated, cost-based contracts. Our wholesale power transactions in the SPP region are all cost-based due to our market power in the SPP region. As of December 31, 2007, SWEPCo and PSO operate in the SPP region. The FERC also regulates, on a cost basis, our wholesale transmission service and rates except in Texas. The FERC claimed jurisdiction over retail transmission rates when the retail rates are unbundled in connection with restructuring. CSPCo's and OPCo's rates in Ohio and APCo's retail rates in Virginia are unbundled. Therefore, our retail transmission rates are based on FERC's Open Access Transmission Tariff (OATT) rates that are cost-based. Although our retail rates are unbundled in Texas, retail transmission rates are still regulated, on a cost basis, by the state regulatory commission. In addition, FERC regulates the SIA, the AEP Power Pool, the CSW Operating Agreement, the System Transmission Integration Agreement, the Transmission Equalization Agreement, the Transmission Coordination Agreement and the System Interim Allowance Agreement, all of which allocate shared system costs and revenues to the AEP utility subsidiaries that are parties to the agreements. The state regulatory commissions regulate all of our retail public utility services/operations (generation/power supply, transmission and distribution operations) and rates except in Ohio and the ERCOT region of Texas. Our retail generation/power supply operations and rates for CSPCo and OPCo in Ohio are no longer cost-based regulated and are on a transition to market-based rates. These rates are currently subject to rate stabilization plans which expire on December 31, 2008. Under the present legislation in Ohio, rates are scheduled to be market-based starting in January 2009. However, legislation is under consideration that may extend that transition date. In the ERCOT region of Texas, the generation/supply business is under customer choice and market pricing. AEP has no Texas jurisdictional retail generation/power supply operations other than a min
New Accounting Pronouncements and Cumulative Effect of Accounting Change	NEW ACCOUNTING PRONOUNCEMENTS Upon issuance of exposure drafts or final pronouncements, we thoroughly review the new accounting literature to determine the relevance, if any, to our business. The following represents a summary of final pronouncements that we have determined relate to our operations. 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 establishes 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. SFAS 141R 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 is effective prospectively for business combinations with an acquisition date on or after the beginning of the first annual reporting period after December 15, 2008. Early adoption is prohibited. We will adopt SFAS 141R effective January 1, 2009 and apply it to any business combinations on or after that date. SFAS 157 "Fair Value Measurements" (SFAS 157) In September 2006, the FASB issued SFAS 157, enhancing existing guidance for fair value measurement of assets and liabilities and instruments measured at fair value that are classified in shareholders' equity. The statement defines fair value, establishes a fair value measurement framework and expands fair value disclosures. It emphasizes that fair value is market-based with the highest measurement hierarchy level being market prices in active markets. The standard requires fair value measurements be disclosed by hierarchy level, an entity include its own credit standing in the measurement of its liabilities and modifies the transaction price presumption. The standard also nullifies the consensus reached in EITF Issue No. 02-3 "Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities" (EITF 02-3) that prohibited the recognition of trading gains or losses at the inception of a derivative contract, unless the fair value of such derivative is supported by observable market data. In February 2008, the FASB issued FASB Staff Position (FSP) FAS 157-1 "Application of FASB Statement No. 157 to FASB Statement No. 13 and Other Accounting Pronouncements That Address Fair Value Measurements for Purposes of Lease Classification or Measurement under Statement 13" which amends SFAS 157 to exclude SFAS 13 "Accounting for Leases" and other accounting pronouncements that address fair value measurements for purposes of lease classification or measurement under SFAS 13. In February 2008, the FASB issued FSP FAS 157-2 "Effective Date
Extraordinary Items Disclosure [Text Block]	EXTRAORDINARY ITEMS Virginia Restructuring In April 2007, Virginia passed legislation to reestablish regulation for retail generation and supply of electricity. As a result, we recorded an extraordinary loss of $118 million ($79 million, net of tax) in 2007 for the reestablishment of regulatory assets and liabilities related to our Virginia retail generation and supply operations. In 2000, we discontinued SFAS 71 regulatory accounting in our Virginia jurisdiction for retail generation and supply operations due to the passage of legislation for customer choice and deregulation. See "Virginia Restructuring" section of Note 4. Texas Stranded Costs Recovery Results for 2005 reflect net adjustments made by TCC to its net true-up regulatory asset for the PUCT's final order in its True-up Proceeding issued in February 2006. Based on the final order, TCC's net true-up regulatory asset was reduced by $384 million. Of the $384 million, $345 million ($225 million, net of tax) was recorded as an extraordinary item in accordance with SFAS 101 "Regulated Enterprises - Accounting for the Discontinuation of Application of FASB Statement No. 71" and is reflected in Extraordinary Loss, Net of Tax on our Consolidated Statement of Income.
Goodwill and Intangible Assets Disclosure [Text Block]	3.GOODWILL AND OTHER INTANGIBLE ASSETS Goodwill The changes in our carrying amount of goodwill for the years ended December 31, 2007 and 2006 by operating segment are as follows:Utility OperationsMEMCOOperationsAEPConsolidated(in millions)Balance at December 31, 2005$37$39$76Impairment Losses---Balance at December 31, 2006373976Impairment Losses---Balance at December 31, 2007$37$39$76 In the fourth quarters of 2006 and 2007, we performed our annual impairment tests. The fair values of the operations with goodwill were estimated using cash flow projections and other market value indicators. There were no goodwill impairment losses. Other Intangible Assets Acquired intangible assets subject to amortization were $15.2 million at December 31, 2007 and $19.4 million at December 31, 2006, net of accumulated amortization and are included in Deferred Charges and Other on our Consolidated Balance Sheets. The amortization life, gross carrying amount and accumulated amortization by major asset class are as follows: December 31,20072006Amortization LifeGross Carrying AmountAccumulated AmortizationGross Carrying AmountAccumulated Amortization(in years)(in millions) Patent5$0.1$0.1$0.1$0.1 Easements102.21.42.21.1Purchased Technology1010.96.410.95.4Advanced Royalties1029.419.529.416.6Total$42.6$27.4$42.6$23.2 Amortization of intangible assets was $4 million, $5 million and $4 million for 2007, 2006 and 2005, respectively. Our estimated total amortization is $3 million for 2008, $2 million per year for 2009 through 2012 and $1 million per year for 2013 through 2016, when all assets will be fully amortized with no residual value. The Advanced Royalties asset class relates to the lignite mine of Dolet Hills Lignite Company, a wholly-owned subsidiary of SWEPCo. In 2008, we expect to receive an order from the LPSC that will extend the useful life of the mine for an additional six years, which is factored in the estimates noted above. Other than goodwill, we have no intangible assets that are not subject to amortization.
Public Utilities, Disclosure of Rate Matters	4.RATE MATTERS Our subsidiaries are involved in rate and regulatory proceedings at the FERC and their state commissions. This note is a discussion of rate matters and industry restructuring related proceedings that could have a material effect on the results of operations and cash flows. Ohio Rate Matters Ohio Restructuring and Rate Stabilization Plans CSPCo and OPCo have three automatic annual generation rate increases of 3% and 7%, respectively, the last of which became effective January 1, 2008. The RSP also allows additional annual generation rate increases of up to an average of 4% per year to recover new governmentally-mandated costs. In March 2007, CSPCo also filed an application under the average 4% generation rate provision of its RSP to adjust the Power Acquisition Rider (PAR) related to CSPCo's acquisition of Monongahela Power Company's certified territory in Ohio. The PAR was increased to recover the cost of a new purchase power market contract to serve the load for that service territory. The PUCO approved this requested increase, which increased CSPCo's revenues by $22 million in 2007, and is expected to increase 2008 revenues by $38 million. In May 2007, the PUCO approved a settlement agreement resolving the Ohio Supreme Court's remand of the PUCO's RSP order. The settling parties agreed to have CSPCo and OPCo take bids for Renewable Energy Certificates (RECs). Under the approved settlement, CSPCo and OPCo will give customers the option to pay a generation rate premium that would encourage the development of renewable energy sources by reimbursing CSPCo and OPCo for the cost of the RECs. In May 2007, CSPCo and OPCo implemented proposed increases from the average 4% proceeding of $24 million and $8 million, respectively, subject to refund. In October 2007, the PUCO issued an order that granted CSPCo and OPCo an annual increase of $19 million and $4 million, respectively. In September 2007, CSPCo and OPCo recorded a provision to refund the over-collected revenues. On January 30, 2008, the PUCO approved a settlement agreement among CSPCo, OPCo and other parties related to an additional average 4% generation rate increase and TCRR adjustments for additional governmentally-mandated costs including increased environmental costs and PJM's revision of its pricing methodology for transmission line losses. Under the settlement, the PUCO approved recovery through the TCRR increased PJM costs associated with transmission line losses of $39 million each for CSPCo and OPCo. As a result, CSPCo and OPCo established regulatory assets in the first quarter of 2008 of $12 million and $14 million, respectively, related to increased PJM costs from June 2007 to December 2007. See the "PJM Marginal-Loss Pricing" in the "FERC Rate Matters" section of this note. The PUCO also approved a credit applied to the TCRR of $10 million for OPCo and $8 million for CSPCo for PJM net congestion costs. To the extent that collections for the TCRR items are over/under actual net costs, we will adjust billings to reflect actual costs including carrying costs. Under the terms of the settlement, although the increased PJM costs associated with transmission line losses w
Commitments and Contingencies Disclosure [Text Block]	COMMITMENTS 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. Insurance and Potential Losses We maintain insurance coverage normal and customary for an integrated electric utility, subject to various deductibles. Our insurance includes coverage for all risks of physical loss or damage to our nonnuclear assets, subject to insurance policy conditions and exclusions. Covered property generally includes power plants, substations, facilities and inventories. Excluded property generally includes transmission and distribution lines, poles and towers. Our insurance programs also generally provide coverage against loss arising from certain claims made by third parties and are in excess of retentions absorbed by us. Coverage is generally provided by a combination of a South Carolina domiciled protected-cell captive insurance company together with and/or in addition to various industry mutual and commercial insurance carriers. See Note 10 for a discussion of nuclear exposures and related insurance. Some potential losses or liabilities may not be insurable or the amount of insurance carried may not be sufficient to meet potential losses and liabilities, including, but not limited to, liabilities relating to damage to the Cook Plant and costs of replacement power in the event of a nuclear incident at the Cook Plant. Future losses or liabilities, if they occur, which are not completely insured, unless recovered from customers, could have a material adverse effect on our results of operations, cash flows and financial condition. COMMITMENTS Construction and Commitments The AEP System has substantial construction commitments to support its operations and environmental investments. In managing the overall construction program and in the normal course of business, we contractually commit to third-party construction vendors for certain material purchases and other construction services. Aggregate construction expenditures for 2008 through 2010 for consolidated operations are estimated at approximately $11.2 billion. The amounts for 2008, 2009 and 2010 are $3,830 million, $3,750 million and $3,600 million, respectively. In addition, we expect to invest approximately $35 million, $70 million and $150 million in our transmission joint ventures in 2008, 2009 and 2010, respectively. Estimated construction expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental regulations, business opportunities, market volatility, economic trends, weather, legal reviews and the ability to access capital. Our subsidiaries enter into long-term contracts to acquire fuel for electric generation and transpo
Guarantees	GUARANTEES There are certain immaterial liabilities recorded for guarantees in accordance with FIN 45 "Guarantor's Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others." 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, debt service reserves and credit enhancements for issued bonds. As the parent company, we issued all of these LOCs in our ordinary course of business on behalf of our subsidiaries. At December 31, 2007, the maximum future payments for all the LOCs are approximately $65 million with maturities ranging from February 2008 to December 2008. 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 46. 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, at an estimated cost of approximately $39 million. As of December 31, 2007, SWEPCo has collected approximately $33 million through a rider for final mine closure costs, of which approximately $16 million is recorded in Deferred Credits and Other and approximately $17 million is recorded in Asset Retirement Obligations on our Consolidated Balance Sheets. Sabine charges SWEPCo, its only customer, all of its costs. SWEPCo passes these costs through its fuel clause. Indemnifications and Other Guarantees Contracts We enter into several types of contracts which require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. The status of certain sales agreements is discussed in the "Dispositions" section of Note 8. These sale agreements include indemnifications with a maximum exposure related to the collective purchase price, which is approximately $1.4 billion (approximately $1 billion relates to the HPL sale which remains unsettled due to the Bank of America (BOA) litigation, see "Enron Bankruptcy" section of this note). There are no material liabilities recorded for any indemnifications. Master Operating Lease We lease certain equipment under a master operating lease. Under the lease ag
Company-wide Staffing and Budget Review	7.COMPANY-WIDE STAFFING AND BUDGET REVIEW As a result of a 2005 company-wide staffing and budget review, we identified approximately 500 positions for elimination. We recorded pretax severance benefits expense of $28 million, which is primarily reflected in Other Operation and Maintenance on our 2005 Consolidated Statement of Income. Approximately 95% of the expense was within the Utility Operations segment. The following table shows the total 2005 expense recorded and the activity during 2005 through 2006, which eliminated the accrual as of June 30, 2006: Amount (in millions) Total Expense$28 Less: Total Payments 16Accrual at December 31, 200512Less: Total Payments8Less: Accrual Adjustments4Accrual at December 31, 2006$- The favorable 2006 accrual adjustments were recorded primarily in Other Operation and Maintenance on our 2006 Consolidated Statement of Income.
Property, Plant and Equipment, Schedule of Significant Acquisitions and Disposals [Text Block]	ACQUISITIONS 2007 Darby Electric Generating Station (Utility Operations segment) In November 2006, CSPCo agreed to purchase Darby Electric Generating Station (Darby) from DPL Energy, LLC, a subsidiary of The Dayton Power and Light Company, for $102 million and the assumption of liabilities of $2 million. CSPCo completed the purchase in April 2007. The Darby Plant is located near Mount Sterling, Ohio and is a natural gas, simple cycle power plant with a generating capacity of 480 MW. Lawrenceburg Generating Station (Utility Operations segment) In January 2007, AEGCo agreed to purchase Lawrenceburg Generating Station (Lawrenceburg) from an affiliate of Public Service Enterprise Group (PSEG) for $325 million and the assumption of liabilities of $3 million. AEGCo completed the purchase in May 2007. The Lawrenceburg Plant is located in Lawrenceburg, Indiana, adjacent to I&M's Tanners Creek Plant, and is a natural gas, combined cycle power plant with a generating capacity of 1,096 MW. AEGCo sells the power to CSPCo through a FERC-approved unit power contract. Dresden Plant (Utility Operations segment) In August 2007, AEGCo agreed to purchase the partially completed Dresden Plant from Dominion Resources, Inc. for $85 million and the assumption of liabilities of $2 million. AEGCo completed the purchase in September 2007. AEGCo incurred approximately $7 million in construction costs at the Dresden Plant in 2007 and expects to incur approximately $175 million in additional costs (excluding AFUDC) prior to completion. The Dresden Plant is located near Dresden, Ohio and is a natural gas, combined cycle power plant. When completed in 2010, the Dresden Plant will have a generating capacity of 580 MW. 2006 None 2005 Waterford Plant (Utility Operations segment) In May 2005, CSPCo signed a purchase-and-sale agreement with Public Service Enterprise Group Waterford Energy LLC, a subsidiary of PSEG, for the purchase of the Waterford Plant in Waterford, Ohio. The Waterford Plant is a natural gas, combined cycle power plant with a generating capacity of 821 MW. This transaction was completed in September 2005 for $218 million and the assumption of liabilities of approximately $2 million. Monongahela Power Company (Utility Operations segment) In June 2005, the PUCO ordered CSPCo to explore the purchase of the Ohio service territory of Monongahela Power Company (Monongahela Power), which included approximately 29,000 customers. In August 2005, we agreed to terms of a transaction, which included the transfer of Monongahela Power's Ohio customer base and the assets, at net book value, that serve those customers to CSPCo. This transaction was completed in December 2005 for approximately $42 million and the assumption of liabilities of approximately $2 million. In addition, CSPCo paid $10 million to compensate Monongahela Power for its termination of certain litigation in Ohio. Therefore, beginning January 1, 2006, CSPCo began serving customers in this additional portion of its service territory. CSPCo's $10 million payment was recorded as a regulatory asset and is being recovered with a carrying cost from all of CSPCo's customers over approximately 5 years. Also includ
Disposal Groups, Including Discontinued Operations, Disclosure [Text Block]	DISCONTINUED OPERATIONS Management periodically assesses our overall business model and makes decisions regarding our continued support and funding of our various businesses and operations. When it is determined that we will seek to exit a particular business or activity and we have met the accounting requirements for reclassification, we will reclassify those businesses or activities as discontinued operations. The assets and liabilities of these discontinued operations are classified in Assets Held for Sale and Liabilities Held for Sale until the time that they are sold. Certain of our operations were determined to be discontinued operations and are classified as such in 2007, 2006 and 2005. Results of operations of these businesses are classified as shown in the following table: SEE-BOARD (a)LIG (b)U.K. Generation (c)Total (in millions)2007 Revenue$-$-$-$-2007 Pretax Income--772007 Earnings, Net of Tax4-20242006 Revenue$-$-$-$-2006 Pretax Income--992006 Earnings, Net of Tax5-5102005 Revenue (Expense)$13$-$(7)$62005 Pretax Income (Loss)10-(13)(3)2005 Earnings (Loss), Net of Tax245(2)27 (a)Relates to purchase price true-up adjustments and tax adjustments from the sale of SEEBOARD.(b)Includes LIG Pipeline Company and subsidiaries and Jefferson Island Storage & Hub LLC. The 2005 amounts relate to purchase price true-up adjustments and tax adjustments from the sale. (c)The 2007 and 2006 amounts relate to a release of accrued liabilities for the London office sublease and tax adjustments from the sale. The 2005 amounts relate to purchase price true-up adjustments and tax adjustments from the sale. In July 2004, we completed the sale of our U.K. Operations, which included the sale of two coal-fired generation plants, coal assets and a number of commodities contracts.
Property, Plant and Equipment Impairment or Disposal Disclosure	ASSET IMPAIRMENTS 2007 None 2006 We recorded a pretax impairment of assets totaling $209 million as a result of the terms of our agreement to sell the Plaquemine Cogeneration Facility to Dow. See "Plaquemine Cogeneration Facility" section of this note for additional information regarding this sale. 2005 We recorded pretax impairments of assets totaling $46 million ($39 million related to asset impairments and $7 million related to an equity investment impairment) that reflected our decision to retire two generation units and our decision to exit noncore businesses and other factors as follows: Conesville Units 1 and 2 (Utility Operations segment) In the third quarter of 2005, following management's extensive review of the commercial viability of our generation fleet, management committed to a plan to retire CSPCo's Conesville Units 1 and 2 before the end of their previously estimated useful lives. As a result, Conesville Units 1 and 2 were retired as of the third quarter of 2005. We recognized a pretax charge of approximately $39 million in 2005 related to our decision to retire the units. The impairment amount is classified in Asset Impairments and Other Related Charges on our 2005 Consolidated Statement of Income. Compresion Bajio S de R.L. de C.V. (All Other) In September 2005, a pretax other-than-temporary impairment charge of approximately $7 million was recognized based on an indicative offer for the sale of our 50% interest in Bajio. The 2005 impairment amount is classified as Investment Value Losses on our Consolidated Statements of Income. The sale was completed in February 2006 with no significant effect on our 2006 results of operations. The categories of impairments and gains on dispositions include: Years Ended December 31,200720062005Asset Impairments and Other Related Charges (Pretax)(in millions) Plaquemine Cogeneration Facility $-$209$- Conesville Units 1 and 2--39Total$-$209$39Gain (Loss) on Disposition of Assets, Net (Pretax) Texas REPs$20$70$112Revenue Sharing on Plaquemine Cogeneration Facility10--Gain on Sale of Land Rights and Other Miscellaneous Property, Plant and Equipment11(1)8Total$41$69$120Investment Value Losses (Pretax)Bajio$-$-$7Gain on Disposition of Equity Investments, Net (Pretax)Sweeny Cogeneration Plant$47$-$-Pacific Hydro Limited--56Other-3- Total$47$3$56
Disclosure of Long Lived Assets Held-for-sale [Text Block]	ASSETS HELD FOR SALE Texas Plants - Oklaunion Power Station (Utility Operations segment) In February 2007, TCC sold its 7.81% share of Oklaunion Power Station to the Public Utilities Board of the City of Brownsville. We classified TCC's assets related to the Oklaunion Power Station in Assets Held for Sale on our Consolidated Balance Sheets at December 31, 2006. The plant did not meet the "component-of-an-entity" criteria because it does not have cash flows that can be clearly distinguished operationally and because it does not operate individually, but rather as a part of the AEP System. Assets Held for Sale at December 31, 2007 and 2006 were as follows: December 31, 20072006 Texas Plants(in millions) Other Current Assets$-$1Property, Plant and Equipment, Net-43Total Assets Held for Sale$-$44
Benefit Plans	9.BENEFIT PLANS We sponsor two qualified pension plans and two nonqualified pension plans. A substantial majority of our employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. We sponsor other postretirement benefit plans to provide medical and life insurance benefits for retired employees. We adopted SFAS 158 as of December 31, 2006. It requires employers to fully recognize the obligations associated with defined benefit pension plans and OPEB plans, which include retiree healthcare, in their balance sheets. Previous standards required an employer to disclose the complete funded status of its plan only in the notes to the financial statements and provided that an employer delay recognition of certain changes in plan assets and obligations that affected the costs of providing benefits resulting in an asset or liability that often differed from the plan's funded status. SFAS 158 requires a defined benefit pension or postretirement plan sponsor to (a) recognize in its statement of financial position an asset for a plan's overfunded status or a liability for the plan's underfunded status, (b) measure the plan's assets and obligations that determine its funded status as of the end of the employer's fiscal year and (c) recognize, as a component of other comprehensive income, the changes in the funded status of the plan that arise during the year but are not recognized as a component of net periodic benefit cost pursuant to previous standards. It also requires an employer to disclose additional information on how delayed recognition of certain changes in the funded status of a defined benefit pension or OPEB plan affects net periodic benefit costs for the next fiscal year. We recorded a SFAS 71 regulatory asset for qualifying SFAS 158 costs of our regulated operations that for ratemaking purposes will be deferred for future recovery. The effect of this standard on our 2006 financial statements was a pretax AOCI adjustment of $1,236 million that was offset by a SFAS 71 regulatory asset of $875 million and a deferred income tax asset of $126 million resulting in a net of tax AOCI equity reduction of $235 million. SFAS 158 requires adjustment of pretax AOCI at the end of each year, for both underfunded and overfunded defined benefit pension and OPEB plans, to an amount equal to the remaining unrecognized deferrals for unamortized actuarial losses or gains, prior service costs and transition obligations, such that remaining deferred costs result in an AOCI equity reduction and deferred gains result in an AOCI equity addition. The year-end AOCI measure can be volatile based on fluctuating investment returns and discount rates. The following tables provide a reconciliation of the changes in the plans' projected benefit obligations and fair value of assets over the two-year period ending at the plan's measurement date of December 31, 2007, and their funded status as of December 31 of each year: Projected Pension Obligations, Plan Assets, Funded Status as of December 31, 2007 and 2006 Pension PlansOther Postretirement Benefit Plans 2007200620072006Change in Projected Benefit Obligation(in millions)Projected
Business Segments	11.BUSINESS SEGMENTS Our primary business strategy and the core of our business focus on our electric utility operations. Within our Utility Operations segment, we centrally dispatch all generation assets and manage our overall utility operations on an integrated basis because of the substantial impact of cost-based rates and regulatory oversight. Generation/supply in Ohio continues to have commission-determined rates transitioning from cost-based to market-based rates. The legislature in Ohio is currently considering possibly returning to some form of cost-based rate-regulation or a hybrid form of rate-regulation for generation. While our Utility Operations segment remains our primary business segment, other segments include our MEMCO Operations segment with significant barging activities and our Generation and Marketing segment, which includes our nonregulated generating, marketing and risk management activities 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. MEMCO Operations "Barging operations that annually transport approximately 35 million tons of coal and dry bulk commodities primarily on the Ohio, Illinois and lower Mississippi Rivers. Approximately 39% of the barging is for agricultural products, 30% for coal, 14% for steel and 17% for other commodities. Generation and Marketing "Wind farms and marketing and risk management activities primarily in ERCOT. Our 50% interest in Sweeny Cogeneration Plant was sold in October 2007. See "Sweeny Cogeneration Plant" section of Note 8. The remainder of our company's activities is presented as All Other. While not considered a business segment, All Other includes: "Parent company's guarantee revenue received from affiliates, interest income and interest expense and other nonallocated costs. "Tax and interest expense adjustments related to our UK operations and SEEBOARD, which were sold in 2004 and 2002, respectively. "Our gas pipeline and storage operations, which were sold in 2004 and 2005."Other energy supply related businesses, including the Plaquemine Cogeneration Facility, which was sold in 2006. The tables below present our reportable segment information for the years ended December 31, 2007, 2006 and 2005 and balance sheet information as of December 31, 2007 and 2006. These amounts include certain estimates and allocations where necessary. Nonutility Operations Utility OperationsMEMCO OperationsGenerationandMarketingAll Other (a)Reconciling AdjustmentsConsolidated (in millions) Year Ended December 31, 2007Revenues from:External Customers$12,101(e)$523$708$48$-$13,380Other Operating Segments554(e)14(406)(13)(149)-Total Revenues$12,655$537$302$35$(149)$13,380 Depreciation and Amortization$1,483$11$29$2$(12)(b)$1,513Interest Income21-381(70)35Interest Expense787528108(87)(b)841Income Tax Expense (Credit)486355(10)-516 Income (Loss) Before Discontinued Operations, Extraordinary Loss an
Derivative Instruments and Hedging Activities Disclosure [Text Block]	DERIVATIVES AND HEDGING SFAS 133 requires recognition of all qualifying derivative instruments as either assets or liabilities in the statement of financial position 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 and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. Because energy markets are imperfect and volatile, there are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract's term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. Derivative contracts that have been designated as normal purchases or normal sales under SFAS 133 are not subject to MTM accounting treatment and are recognized in the Consolidated 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 fair value hedges (i.e. hedging the exposure to changes in the fair value of an asset, liability or an identified portion thereof that is attributable to a particular risk), we recognize the gain or loss on the derivative instrument as well as the offsetting loss or gain on the hedged item associated with the hedged risk in earnings during the period of change. For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is 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 Consolidated Balance Sheets until the period the hedged item affects earnings. We recognize any hedge ineffectiveness in earnings immediately during the period of change, except in regula
Financial Instruments	FINANCIAL INSTRUMENTS The fair value of Long-term Debt is based on quoted market prices for the same or similar issues and the current dividend or 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 significant financial instruments at December 31, 2007 and 2006 are summarized in the following tables.December 31, 20072006Book ValueFair ValueBook ValueFair Value(in millions)Long-term Debt$14,994$14,917$13,698$13,743
Income Tax Disclosure [Text Block]	13. INCOME TAXES The details of our consolidated income taxes before discontinued operations, extraordinary loss and cumulative effect of accounting change as reported are as follows:Years Ended December 31,200720062005(in millions)Federal:Current$464$429$375Deferred35528Total499434403State and Local:Current16125Deferred16(10)4Total175129International:Current--(2)Deferred---Total--(2)Total Income Tax Expense Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change$516$485$430 The following is a reconciliation of our consolidated difference between the amount of federal income taxes computed by multiplying book income before income taxes by the federal statutory tax rate and the amount of income taxes reported. Years Ended December 31, 200720062005 (in millions) Net Income$1,089$1,002$814 Discontinued Operations (Net of Income Tax of $(18) Million, $(1) Million and $(30) Million in 2007, 2006 and 2005, respectively)(24)(10)(27)Extraordinary Loss, (Net of Income Tax of $(39) Million and $(121) Million in 2007 and 2005, respectively)79-225Cumulative Effect of Accounting Change (Net of Income Tax of $(9) Million in 2005)--17Preferred Stock Dividends337Income Before Preferred Stock Dividends of Subsidiaries1,1479951,036Income Tax Expense Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change516485430 Pretax Income$1,663$1,480$1,466 Income Taxes on Pretax Income at Statutory Rate (35%)$582$518$513Increase (Decrease) in Income Taxes Resulting from the Following Items:Depreciation293839Investment Tax Credits, Net(24)(29)(32)Tax Effects of International Operations--(2)Energy Production Credits(18)(19)(18)State Income Taxes113319Removal Costs(21)(15)(14)AFUDC(18)(18)(14)Medicare Subsidy(12)(12)(13)Tax Reserve Adjustments(8)9(11)Other(5)(20)(37)Total Income Tax Expense Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change$516$485$430Effective Income Tax Rate31.0%32.8%29.3% The following table shows elements of the net deferred tax liability and significant temporary differences: December 31, 20072006 (in millions) Deferred Tax Assets$2,284$2,384Deferred Tax Liabilities(7,023)(7,074)Net Deferred Tax Liabilities$(4,739)$(4,690)Property-Related Temporary Differences$(3,300)$(3,292) Amounts Due from Customers for Future Federal Income Taxes(202)(193)Deferred State Income Taxes(324)(318)Transition Regulatory Assets(3)(46)Securitized Transition Assets(806)(809)Regulatory Assets(225)(334)Accrued Pensions(211)(155)Deferred Income Taxes on Other Comprehensive Loss83120 Accrued Nuclear Decommissioning(286)(247) All Other, Net535584 Net Deferred Tax Liabilities$(4,739)$(4,690) 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 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 reflect
Stock-Based Compensation	16.STOCK-BASED COMPENSATION As previously approved by shareholder vote, the Amended and Restated American Electric Power System Long-Term Incentive Plan (LTIP) authorizes the use of 19,200,000 shares of AEP common stock for various types of stock-based compensation awards, including stock option awards, to key employees. A maximum of 9,000,000 shares may be used under this plan for full value share awards, which include performance units, restricted shares and restricted stock units. The Board of Directors and shareholders both adopted the original LTIP in 2000 and the amended and restated version in 2005. We did not grant stock options in 2007 or 2006 and granted only 10,000 stock options in 2005. The following sections provide further information regarding each type of stock-based compensation award granted by the Board of Directors. We adopted SFAS 123 (revised 2004) "Share-Based Payments" (SFAS 123R), effective January 1, 2006. Stock Options For all stock options granted, the exercise price equaled or exceeded the market price of AEP's common stock on the date of grant. Stock options were granted with a ten-year term and generally vested, subject to the participant's continued employment, in approximately equal 1/3 increments on January 1st of the year following the first, second and third anniversary of the grant date. We record compensation cost for stock options over the vesting period based on the fair value on the grant date. The LTIP does not specify a maximum contractual term for stock options. The total fair value of stock options vested and the total intrinsic value of options exercised are as follows: Years Ended December 31, 200720062005 Stock Options(in thousands)Fair Value of Stock Options Vested$1,377$3,667$5,036 Intrinsic Value of Options Exercised (a)29,38916,82312,091 (a) Intrinsic value is calculated as market price at exercise date less the option exercise price. A summary of AEP stock option transactions during the years ended December 31, 2007, 2006 and 2005 is as follows:200720062005OptionsWeighted Average Exercise PriceOptionsWeighted Average Exercise PriceOptionsWeighted Average Exercise Price (in thousands) (in thousands)(in thousands) Outstanding at January 1, 3,670$34.416,222$34.168,230$33.29Granted-N/A-N/A1038.65Exercised/Converted(2,454)35.24(2,343)33.12(1,886)36.94Forfeited/Expired(20)35.08(209)41.58(132)31.97 Outstanding at December 31,1,19632.693,67034.416,22234.16Options Exercisable at December 31,1,193$32.683,411$34.835,199$35.40Weighted average exercise price of options:Granted above Market PriceN/AN/AN/AGranted at Market PriceN/AN/A$38.65 The following table summarizes information about AEP stock options outstanding at December 31, 2007. Options Outstanding 2007 Range of Exercise PricesNumber OutstandingWeightedAverageRemainingLifeWeightedAverageExercise PriceAggregateIntrinsic Value(in thousands)(in years)(in thousands)$25.73 - $27.955395.01$27.38$10,335$30.76 - $38.655103.6134.266,275$44.10 - $49.001473.3646.71(22)Total (a)1,1964.2132.69$16,588 (a) Options outstanding are not significantly different from the number of shares expected to vest. The following table summarizes information about AEP stock
Property, Plant and Equipment Disclosure [Text Block]	17.PROPERTY, PLANT AND EQUIPMENT We provide for depreciation of Property, Plant and Equipment, excluding coal-mining properties, on a straight-line basis over the estimated useful lives of property, generally using composite rates by functional class as follows: 2007RegulatedNonregulated Functional Class of PropertyProperty,Plant andEquipmentAccumulated DepreciationAnnual Composite Depreciation Rate RangesDepreciable Life Ranges Property,Plant andEquipment Accumulated DepreciationAnnual Composite Depreciation Rate RangesDepreciable Life Ranges(in millions)(in years)(in millions)(in years)Production$11,278$5,8162.0 - 3.8%9 - 132$8,955$3,4622.0 - 5.1%20 - 121Transmission7,3922,3081.3 - 3.0%25 - 87--N.M.N.M.Distribution12,0563,1163.0 - 3.9%11 - 75--N.M.N.M.CWIP1,864(57)N.M.N.M.1,1552N.M.N.M.Other2,4101,1054.8 - 11.3%5 - 551,035523N.M.N.M.Total$35,000$12,288$11,145$3,987 N.M. = Not Meaningful 2006RegulatedNonregulated Functional Class of PropertyProperty, Plant and EquipmentAccumulated DepreciationAnnual Composite Depreciation Rate RangesDepreciable Life Ranges Property, Plant and EquipmentAccumulated DepreciationAnnual Composite Depreciation Rate RangesDepreciable Life Ranges(in millions)(in years)(in millions)(in years)Production$7,892$4,4372.6 - 3.8%30 - 121$8,895$3,8862.57 - 9.15%20 - 121 Transmission7,0182,3321.6 - 2.9%25 - 87 --N.M.N.M.Distribution11,3383,1213.0 - 4.0%11 - 75--N.M.N.M.CWIP1,423(41)N.MN.M.2,0502N.M.N.M.Other2,4001,0676.7 - 11.5%24 - 551,005436N.M.N.M.Total$30,071$10,916$11,950$4,324 2005RegulatedNonregulated Functional Class of PropertyAnnual Composite Depreciation Rate RangesDepreciable Life Ranges Annual Composite Depreciation Rate RangesDepreciable Life Ranges(in years)(in years)Production2.7 - 3.8%30 - 1202.6 - 3.3%20 - 120Transmission1.7 - 3.0%25 - 75 N.M.N.M.Distribution3.1 - 4.1%10 - 75 N.M.N.M.Other5.1 - 16.0%N.M.2.0 - 4.9%2 - 37 N.M. = Not Meaningful We provide for depreciation, depletion and amortization of coal-mining assets over each asset's estimated useful life or the estimated life of each mine, whichever is shorter, using the straight-line method for mining structures and equipment. We use either the straight-line method or the units-of-production method to amortize mine development costs and deplete coal rights based on estimated recoverable tonnages. We include these costs in the cost of coal charged to fuel expense. The average amortization rate for coal rights and mine development costs was $0.66 per ton in 2007, 2006 and 2005. For cost-based rate-regulated operations, the composite depreciation rate generally includes a component for non-asset retirement obligation (non-ARO) removal costs, which is credited to Accumulated Depreciation and Amortization. Actual removal costs incurred are charged to Accumulated Depreciation and Amortization. Any excess of accrued non-ARO removal costs over actual removal costs incurred is reclassified from Accumulated Depreciation and Amortization and reflected as a regulatory liability. For nonregulated operations, non-ARO removal costs are expensed as incurred (see "Asset Retirement Obligations (ARO)" section of this note). Asset Retirement Obligations (ARO) We implemente
Unaudited Quarterly Financial Information	18.UNAUDITED QUARTERLY FINANCIAL INFORMATION In our opinion, the unaudited quarterly information reflects all normal and recurring accruals and adjustments necessary for a fair presentation of our results of operations for interim periods. Quarterly results are not necessarily indicative of a full year's operations because of various factors. Our unaudited quarterly financial information is as follows:2007 Quarterly Periods EndedMarch 31June 30September 30December 31(in millions - except per share amounts)Revenues$3,169$3,146$3,789$3,276Operating Income (a)545549798427Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change (a)271257407209Discontinued Operations, Net of Tax-2-22Income Before Extraordinary Loss and Cumulative Effect of Accounting Change (a)271259407231Extraordinary Loss, Net of Tax (b)-(79)--Net Income (a)271180407231Basic Earnings (Loss) per Share:Earnings per Share Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change (c)0.680.641.020.52Discontinued Operations, Net of Tax (d)-0.01-0.06 Earnings per Share Before Extraordinary Loss and Cumulative Effect of Accounting Change0.680.651.020.58Extraordinary Loss per Share-(0.20)--Earnings per Share0.680.451.020.58Diluted Earnings (Loss) per Share:Earnings per Share Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change0.680.641.020.52Discontinued Operations, Net of Tax-0.01-0.05 Earnings per Share Before Extraordinary Loss and Cumulative Effect of Accounting Change0.680.651.020.57Extraordinary Loss per Share-(0.20)--Earnings per Share0.680.451.020.57 2006 Quarterly Periods Ended March 31June 30September 30December 31(in millions - except per share amounts)Revenues$3,108$2,936$3,594$2,984Operating Income689371535371Income Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change378172265177 Discontinued Operations, Net of Tax33-4 Income Before Extraordinary Loss and Cumulative Effect of Accounting Change381175265181Net Income381175265181 Basic Earnings per Share: Earnings per Share Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change0.960.440.670.45Discontinued Operations, Net of Tax0.01--0.01 Earnings per Share Before Extraordinary Loss and Cumulative Effect of Accounting Change0.970.440.670.46Earnings per Share0.970.440.670.46Diluted Earnings per Share:Earnings per Share Before Discontinued Operations, Extraordinary Loss and Cumulative Effect of Accounting Change (e)0.950.430.670.44Discontinued Operations, Net of Tax (f)0.010.01-0.02Earnings per Share Before Extraordinary Loss and Cumulative Effect of Accounting Change0.960.440.670.46Earnings per Share 0.960.440.670.46 (a)See "Oklahoma 2007 Ice Storms" section of Note 4 for discussion of expenses incurred from ice storms in January and December 2007.(b)See "Virginia Restructuring" in "Extraordinary Items" section of Note 2 for a discussion of the extraordinary loss booked in the second quarter of 2007.(c)Amounts for 2007 do not add to $2.87 for Basic Earnings per Share Before Discontinued Operations, Extraordinary Loss and Cumulative
Effects of Regulation	5.EFFECTS OF REGULATION Regulatory Assets and Liabilities Regulatory assets and liabilities are comprised of the following items:December 31,Regulatory Assets:20072006Notes(in millions)Current Regulatory Asset - Under-recovered Fuel Costs (p)$11$38(c) (h)SFAS 109 Regulatory Asset, Net (Note 13)$815$771(c) (g)SFAS 158 Regulatory Asset (Note 9)659875(a) (g)Transition Regulatory Assets - Texas, Ohio and Virginia108240(a) (l)Unamortized Loss on Reacquired Debt92105(b) (j)Virginia E&R Costs Recovery Filing (Note 4)8258(c) (n) Customer Choice Deferrals - Ohio (Note 4)5249(b) (m) Unrealized Loss on Forward Commitments3989(a) (g)Lawton Settlement (Note 4)32-(b) (i)Cook Nuclear Plant Refueling Outage Levelization 3447(a) (d)Red Rock Generating Facility (Note 4)21-(b) (m)Other265243(c) (g)Total Noncurrent Regulatory Assets$2,199$2,477Regulatory Liabilities:Current Regulatory Liability - Over-recovered Fuel Costs (o)$64$37(c) (h)Regulatory Liabilities and Deferred Investment Tax Credits:Asset Removal Costs$1,927$1,610(e)Excess ARO for Nuclear Decommissioning Liability (Note 10)362323(f)Deferred Investment Tax Credits311332(c) (k)Unrealized Gain on Forward Commitments103181(a) (g) Excess Deferred State Income Taxes Due to the Phase Out of the Ohio Franchise Tax - Ohio (Ormet - Note 4)4357(g) (a)TCC CTC Refund-155(c)Other206252(c) (g)Total Noncurrent Regulatory Liabilities and Deferred Investment Tax Credits$2,952$2,910 (a)Does not earn a return. (b)Amount effectively earns a return.(c)Includes items both earning and not earning a return.(d)Amortized over the period beginning with the commencement of an outage and ending with the beginning of the next outage. (e)The liability for removal costs, which reduces rate base and the resultant return, will be discharged as removal costs are incurred.(f)This is the difference in the cumulative amount of removal costs recovered through rates and the cumulative amount of ARO as measured by applying SFAS 143. This amount earns a return, accrues monthly and will be paid when the nuclear plant is decommissioned. (g)Recovery/refund period - various periods.(h)Recovery/refund period - 1 year.(i)Recovery/refund period - 3 years.(j)Recovery/refund period - up to 36 years.(k)Recovery/refund period - up to 79 years. (l)Recovery/refund period - up to 8 years.(m)Recovery method and timing to be determined in future proceedings. (n)Approximately $49 million will be recovered over a twelve month period beginning January 1, 2008 with the remaining recovery method and timing to be determined in future proceedings.(o)Current Regulatory Liability - Over-recovered Fuel Costs are recorded in Other on our Consolidated Balance Sheets.(p)Current Regulatory Asset - Under-recovered Fuel Costs are recorded in Prepayments and Other on our Consolidated Balance Sheets.
Nuclear	10.NUCLEAR I&M owns and operates the two-unit 2,110 MW Cook Plant under licenses granted by the NRC. We have a significant future financial commitment to safely dispose of SNF and to 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. Should a nuclear incident occur at any nuclear power plant in the U.S., the resultant liability could be substantial. By agreement, I&M is partially liable, together with all other electric utility companies that own nuclear generating units, for a nuclear power plant incident at any nuclear plant in the U.S. Decommissioning and Low Level Waste Accumulation Disposal The cost to decommission a nuclear plant is affected by NRC regulations and the SNF disposal program. Decommissioning costs are accrued over the service life of the Cook Plant. The estimated cost of decommissioning and disposal of low-level radioactive waste for the Cook Plant ranges from $733 million to $1.3 billion in 2006 nondiscounted dollars. Our most recent decommissioning study was performed in 2006. The wide range is caused by variables in assumptions. I&M recovers estimated decommissioning costs for the Cook Plant in its rates. The amount recovered in rates was $32 million in 2007, $30 million in 2006 and $27 million in 2005. Decommissioning costs recovered from customers are deposited in external trusts. I&M deposited an additional $4 million in 2007, 2006 and 2005 in its decommissioning trust under funding provisions approved by regulatory commissions. At December 31, 2007, the total decommissioning trust fund balance was approximately $1.1 billion. Trust fund earnings increase the fund assets and decrease the amount remaining to be recovered from ratepayers. The decommissioning costs (including interest, unrealized gains and losses and expenses of the trust funds) increase or decrease the recorded liability. I&M continues to work with regulators and customers to recover the remaining estimated costs of decommissioning the Cook Plant. However, future results of operations, cash flows and possibly financial condition would be adversely affected if the cost of SNF disposal and decommissioning continues to increase and cannot be recovered. SNF Disposal The Federal government is responsible for permanent SNF disposal and assesses fees to nuclear plant owners for SNF disposal. A fee of one mill per KWH for fuel consumed after April 6, 1983 at the Cook Plant is being collected from customers and remitted to the U.S. Treasury. At December 31, 2007, fees and related interest of $259 million for fuel consumed prior to April 7, 1983 at the Cook Plant have been recorded as Long-term Debt and funds collected from customers along with related earnings totaling $285 million to pay the fee are recorded as part of Spent Nuclear Fuel and Decommissioning Trust. I&M has not paid the government the pre-April 1983 fees due to continued delays and uncertainties related to the federal disposal program. Trust Assets for Decommissioning and SNF Disposal
Leases	14. LEASES Leases of property, plant and equipment are for periods up to 60 years and require payments of related property taxes, maintenance and operating costs. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases. Lease rentals for both operating and capital leases are generally charged to Other Operation and Maintenance expense in accordance with rate-making treatment for regulated operations. Capital leases for nonregulated property are accounted for as if the assets were owned and financed. The components of rental costs are as follows: Years Ended December 31, 200720062005 Lease Rental Costs(in millions)Net Lease Expense on Operating Leases$364$340$298Amortization of Capital Leases686457Interest on Capital Leases201713Total Lease Rental Costs$452$421$368 The following table shows the property, plant and equipment under capital leases and related obligations recorded on our Consolidated Balance Sheets. Capital lease obligations are included in Current Liabilities - Other and Noncurrent Liabilities - Deferred Credits and Other on our Consolidated Balance Sheets. December 31, 20072006 (in millions) Property, Plant and Equipment Under Capital LeasesProduction$89$94Distribution1515Other458360Construction Work in Progress3930Total Property, Plant and Equipment Under Capital Leases601499Accumulated Amortization 232210Net Property, Plant and Equipment Under Capital Leases$369$289Obligations Under Capital LeasesNoncurrent Liability$267$210Liability Due Within One Year10481Total Obligations Under Capital Leases$371$291 Future minimum lease payments consisted of the following at December 31, 2007: Capital LeasesNoncancelable Operating Leases Future Minimum Lease Payments(in millions)2008$117$337200990311201059283201130250201225230Later Years1491,775Total Future Minimum Lease Payments$470$3,186Less Estimated Interest Element99Estimated Present Value of Future Minimum Lease Payments$371 Rockport Lease AEGCo and I&M entered into a sale-and-leaseback transaction in 1989 with Wilmington Trust Company (Owner Trustee), an unrelated, unconsolidated trustee for Rockport Plant Unit 2 (the Plant). The Owner Trustee was capitalized with equity from six owner participants with no relationship to AEP or any of its subsidiaries and debt from a syndicate of banks and securities in a private placement to certain institutional investors. The gain from the sale was deferred and is being amortized over the term of the lease, which expires in 2022. The Owner Trustee owns the Plant and leases it to AEGCo and I&M. The lease is accounted for as an operating lease with the payment obligations included in the future minimum lease payments schedule earlier in this note. The lease term is for 33 years with potential renewal options. At the end of the lease term, AEGCo and I&M have the option to renew the lease or the Owner Trustee can sell the Plant. Neither AEGCo, I&M nor AEP has an ownership interest in the Owner Trustee and do not guarantee its debt. The future minimum lease payments for this sale-and-leaseback transaction as of December 31, 2007 are as follows: AEGCoI&M Future Minimum Lease Payments(in millions) 200
Financing Activities	15.FINANCING ACTIVITIES Common Stock Common Stock Repurchase In February 2005, our Board of Directors authorized the repurchase of up to $500 million of our common stock from time to time through 2006. In March 2005, we purchased 12.5 million shares of our outstanding common stock through an accelerated share repurchase agreement at an initial price of $34.63 per share plus transaction fees. The purchase of shares in the open market was completed by a broker-dealer in May 2005 and we received a purchase price adjustment of $6.45 million based on the actual cost of the shares repurchased. Based on this adjustment, our actual stock purchase price averaged $34.18 per share. Management has not established a timeline for the buyback of the remaining stock under this plan. Equity Units and Remarketing of Senior Notes In June 2002, AEP issued 6.9 million equity units at $50 per unit and received proceeds of $345 million. Each equity unit consisted of a forward purchase contract and a senior note. In June 2005, we remarketed and settled $345 million of our 5.75% senior notes at a new interest rate of 4.709%. The senior notes matured on August 16, 2007. We did not receive any proceeds from the mandatory remarketing. Issuance of Common Stock On August 16, 2005, we issued approximately 8.4 million shares of common stock in connection with the settlement of forward purchase contracts that formed a part of our outstanding 9.25% equity units. In exchange for $50 per equity unit, holders of the equity units received 1.2225 shares of AEP common stock for each purchase contract and cash in lieu of fractional shares. Each holder was not required to make any additional cash payment. The equity unit holder's purchase obligation was satisfied from the proceeds of a portfolio of U.S. Treasury securities held in a collateral account that matured on August 1, 2005. The portfolio of U.S. Treasury securities was acquired in connection with the June 2005 remarketing of the senior notes discussed above. We issued 2.4 million, 2.3 million and 1.9 million shares of common stock in connection with our stock option plan during 2007, 2006 and 2005, respectively. Set forth below is a reconciliation of common stock share activity for the years ended December 31, 2007, 2006 and 2005:Shares of Common StockIssuedHeld in Treasury Balance, January 1, 2005404,858,1458,999,992Issued10,360,685-Treasury Stock Acquisition-12,500,000Balance, December 31, 2005415,218,83021,499,992Issued2,955,898-Balance, December 31, 2006418,174,72821,499,992Issued3,751,968-Balance, December 31, 2007421,926,69621,499,992 Preferred Stock Information about the components of preferred stock of our subsidiaries is as follows: December 31, 2007 Call Price Per Share (a)Shares Authorized (b)Shares Outstanding (c)Amount (in millions)Not Subject to Mandatory Redemption:4.00% - 5.00%$102-$1101,525,903606,878$61December 31, 2006Call Price Per Share (a)Shares Authorized (b)Shares Outstanding (c)Amount (in millions)Not Subject to Mandatory Redemption:4.00% - 5.00%$102-$1101,525,903607,044$61 (a)At the option of the subsidiary, the shares may be redeemed at the call price plus accrued dividends. The involuntary liquida