UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Quarterly Period Ended March 31, 2006

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For The Transition Period from ____ to ____

Commission	Registrant, State of Incorporation,	I.R.S. Employer
File Number	Address of Principal Executive Offices, and Telephone Number	Identification No.

1-3525	AMERICAN ELECTRIC POWER COMPANY, INC. (A New York Corporation)	13-4922640
0-18135	AEP GENERATING COMPANY (An Ohio Corporation)	31-1033833
0-346	AEP TEXAS CENTRAL COMPANY (A Texas Corporation)	74-0550600
0-340	AEP TEXAS NORTH COMPANY (A Texas Corporation)	75-0646790
1-3457	APPALACHIAN POWER COMPANY (A Virginia Corporation)	54-0124790
1-2680	COLUMBUS SOUTHERN POWER COMPANY (An Ohio Corporation)	31-4154203
1-3570	INDIANA MICHIGAN POWER COMPANY (An Indiana Corporation)	35-0410455
1-6858	KENTUCKY POWER COMPANY (A Kentucky Corporation)	61-0247775
1-6543	OHIO POWER COMPANY (An Ohio Corporation)	31-4271000
0-343	PUBLIC SERVICE COMPANY OF OKLAHOMA (An Oklahoma Corporation)	73-0410895
1-3146	SOUTHWESTERN ELECTRIC POWER COMPANY (A Delaware Corporation)	72-0323455

All Registrants	1 Riverside Plaza, Columbus, Ohio 43215-2373
	Telephone (614) 716-1000

Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.
Yes X	No ___

Indicate by check mark whether American Electric Power Company, Inc. is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)

Large accelerated filer X Accelerated filer ___ Non-accelerated filer ___

Indicate by check mark whether AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company, are large accelerated filers, accelerated filers, or non-accelerated filers. See definition of ‘accelerated filer and large accelerated filer’ in Rule 12b-2 of the Exchange Act. (Check One)
Large accelerated filer ___ Accelerated filer ___ Non-accelerated filer X

Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act.)
Yes ___	No X

AEP Generating Company, AEP Texas North Company, Columbus Southern Power Company, Kentucky Power Company and Public Service Company of Oklahoma meet the conditions set forth in General Instruction H(1)(a) and (b) of Form 10-Q and are therefore filing this Form 10-Q with the reduced disclosure format specified in General Instruction H(2) to Form 10-Q.

	Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2005, the last trading date of the registrants’ most recently completed second fiscal quarter	Number of shares of common stock outstanding of the registrants at April 28, 2006

AEP Generating Company	None	1,000
		($1,000 par value)
AEP Texas Central Company	None	2,211,678
		($25 par value)
AEP Texas North Company	None	5,488,560
		($25 par value)
American Electric Power Company, Inc.	$14,172,701,867	393,914,882
		($6.50 par value)
Appalachian Power Company	None	13,499,500
		(no par value)
Columbus Southern Power Company	None	16,410,426
		(no par value)
Indiana Michigan Power Company	None	1,400,000
		(no par value)
Kentucky Power Company	None	1,009,000
		($50 par value)
Ohio Power Company	None	27,952,473
		(no par value)
Public Service Company of Oklahoma	None	9,013,000
		($15 par value)
Southwestern Electric Power Company	None	7,536,640
		($18 par value)

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

INDEX TO QUARTERLY REPORTS ON FORM 10-Q

March 31, 2006


Glossary of Terms

Forward-Looking Information

Part I. FINANCIAL INFORMATION

		Items 1, 2 and 3 - Financial Statements, Management’s Financial Discussion and Analysis and Quantitative and Qualitative Disclosures About Risk Management Activities:
American Electric Power Company, Inc. and Subsidiary Companies:
	Management’s Financial Discussion and Analysis of Results of Operations
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Consolidated Financial Statements

AEP Generating Company:
	Management’s Narrative Financial Discussion and Analysis
	Condensed Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

AEP Texas Central Company and Subsidiary:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

AEP Texas North Company:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Appalachian Power Company and Subsidiaries:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Columbus Southern Power Company and Subsidiaries:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Indiana Michigan Power Company and Subsidiaries:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Kentucky Power Company:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Ohio Power Company Consolidated:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Public Service Company of Oklahoma:
	Management’s Narrative Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Southwestern Electric Power Company Consolidated:
	Management’s Financial Discussion and Analysis
	Quantitative and Qualitative Disclosures About Risk Management Activities
	Condensed Consolidated Financial Statements
	Index to Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Condensed Notes to Condensed Financial Statements of Registrant Subsidiaries

Combined Management’s Discussion and Analysis of Registrant Subsidiaries

	Item 4.	Controls and Procedures

Part II. OTHER INFORMATION

	Item 1.	Legal Proceedings
	Item 1A.	Risk Factors
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds
	Item 5.	Other Information
	Item 6.	Exhibits:
			Exhibit 12
			Exhibit 31(a)
			Exhibit 31(b)
			Exhibit 31(c)
			Exhibit 31(d)
			Exhibit 32(a)
			Exhibit 32(b)

SIGNATURE

This combined Form 10-Q is separately filed by American Electric Power Company, Inc., AEP Generating Company, AEP Texas Central Company, AEP Texas North Company, Appalachian Power Company, Columbus Southern Power Company, Indiana Michigan Power Company, Kentucky Power Company, Ohio Power Company, Public Service Company of Oklahoma and Southwestern Electric Power Company. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Term

Meaning

AEGCo		AEP Generating Company, an AEP electric generating subsidiary.
AEP or Parent		American Electric Power Company, Inc.
AEP Consolidated		AEP and its majority owned consolidated subsidiaries and consolidated entities.
AEP East companies		APCo, CSPCo, I&M, KPCo and OPCo.
AEPES		AEP Energy Services, Inc., a subsidiary of AEP Resources, Inc.
AEP System or the System		American Electric Power System, an integrated electric utility system, owned and operated by AEP’s electric utility subsidiaries.
AEP System Power Pool or AEP Power Pool		Members are APCo, CSPCo, I&M, KPCo and OPCo. The Pool shares the generation, cost of generation and resultant wholesale off-system sales of the member companies.
AEPSC		American Electric Power Service Corporation, a service subsidiary providing management and professional services to AEP and its subsidiaries.
AEP West companies		PSO, SWEPCo, TCC and TNC.
AFUDC		Allowance for Funds Used During Construction.
ALJ		Administrative Law Judge.
APCo		Appalachian Power Company, an AEP electric utility subsidiary.
CAA		Clean Air Act.
Cook Plant		Donald C. Cook Nuclear Plant, a two-unit, 2,110 MW nuclear plant owned by I&M.
CSPCo		Columbus Southern Power Company, an AEP electric utility subsidiary.
CSW		Central and South West Corporation, a subsidiary of AEP (Effective January 21, 2003, the legal name of Central and South West Corporation was changed to AEP Utilities, Inc.).
CSW Operating Agreement		Agreement, dated January 1, 1997, by and among PSO, SWEPCo, TCC and TNC governing their generating capacity allocation. AEPSC acts as the agent.
CTC		Competition Transition Charge.
DETM		Duke Energy Trading and Marketing L.L.C., a risk management counterparty.
EPACT		Energy Policy Act of 2005.
ERCOT		Electric Reliability Council of Texas.
FASB		Financial Accounting Standards Board.
Federal EPA		United States Environmental Protection Agency.
FERC		Federal Energy Regulatory Commission.
GAAP		Accounting Principles Generally Accepted in the United States of America.
HPL		Houston Pipe Line Company LP, a former AEP subsidiary that was sold in January 2005.
IGCC		Integrated Gasification Combined Cycle, technology that turns coal into a cleaner-burning gas.
I&M		Indiana Michigan Power Company, an AEP electric utility subsidiary.
IRS		Internal Revenue Service.
IPP		Independent Power Producers.
IURC		Indiana Utility Regulatory Commission.
KPCo		Kentucky Power Company, an AEP electric utility subsidiary.
KPSC		Kentucky Public Service Commission.
kV		Kilovolt.
KWH		Kilowatthour.
MISO		Midwest Independent Transmission System Operator.

MTM		Mark-to-Market.
MW		Megawatt.
MWH		Megawatthour.
NO_x		Nitrogen oxide.
Nonutility Money Pool		AEP System’s Nonutility Money Pool.
NRC		Nuclear Regulatory Commission.
NSR		New Source Review.
NYMEX		New York Mercantile Exchange.
OATT		Open Access Transmission Tariff.
OCC		Corporation Commission of the State of Oklahoma.
OPCo		Ohio Power Company, an AEP electric utility subsidiary.
OTC		Over the counter.
PJM		Pennsylvania - New Jersey - Maryland regional transmission organization.
PSO		Public Service Company of Oklahoma, an AEP electric utility subsidiary.
PTB		Price-to-Beat.
PUCO		Public Utilities Commission of Ohio.
PUCT		Public Utility Commission of Texas.
PURPA		Public Utility Regulatory Policies Act of 1978.
Registrant Subsidiaries		AEP subsidiaries which are SEC registrants; AEGCo, APCo, CSPCo, I&M, KPCo, OPCo, PSO, SWEPCo, TCC and TNC.
REP		Texas Retail Electric Provider.
Risk Management Contracts		Trading and nontrading derivatives, including those derivatives designated as cash flow and fair value hedges.
Rockport Plant		A generating plant, consisting of two 1,300 MW coal-fired generating units near Rockport, Indiana owned by AEGCo and I&M.
RTO		Regional Transmission Organization.
S&P		Standard and Poor’s.
SEC		United States Securities and Exchange Commission.
SECA		Seams Elimination Cost Allocation.
SFAS		Statement of Financial Accounting Standards issued by the FASB.
SFAS 133		Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities.”
SIA		System Integration Agreement.
SO₂		Sulfur Dioxide.
SPP		Southwest Power Pool.
STP		South Texas Project Nuclear Generating Plant.
Sweeny		Sweeny Cogeneration Limited Partnership, owner and operator of a four unit, 480 MW gas-fired generation facility, owned 50% by AEP.
SWEPCo		Southwestern Electric Power Company, an AEP electric utility subsidiary.
TCC		AEP Texas Central Company, an AEP electric utility subsidiary.
TEM		SUEZ Energy Marketing NA, Inc. (formerly known as Tractebel Energy Marketing, Inc.).
Texas Restructuring Legislation		Legislation enacted in 1999 to restructure the electric utility industry in Texas.
TNC		AEP Texas North Company, an AEP electric utility subsidiary.
True-up Proceeding		A filing made under the Texas Restructuring Legislation to finalize the amount of stranded costs and other true-up items and the recovery of such amounts.
Utility Money Pool		AEP System’s Utility Money Pool.
VaR		Value at Risk, a method to quantify risk exposure.
Virginia SCC		Virginia State Corporation Commission.
WPCo		Wheeling Power Company, an AEP electric distribution subsidiary.
WVPSC		Public Service Commission of West Virginia.

FORWARD-LOOKING INFORMATION

This report made by AEP and its Registrant Subsidiaries contains forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934. Although AEP and each of its Registrant Subsidiaries believe that their expectations are based on reasonable assumptions, any such statements may be influenced by factors that could cause actual outcomes and results to be materially different from those projected. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

·	Electric load and customer growth.
·	Weather conditions, including storms.
·	Available sources and costs of, and transportation for, fuels and the creditworthiness of fuel suppliers and transporters.
·	Availability of generating capacity and the performance of our generating plants.
·	Our ability to recover regulatory assets and stranded costs in connection with deregulation.
·	Our ability to recover increases in fuel and other energy costs through regulated or competitive electric rates.
·	Our ability to build or acquire generating capacity when needed at acceptable prices and terms and to recover those costs through applicable rate cases or competitive rates.
·	New legislation, litigation and government regulation including requirements for reduced emissions of sulfur, nitrogen, mercury, carbon and other substances.
·	Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions (including rate or other recovery for new investments, transmission service and environmental compliance).
·	Resolution of litigation (including pending Clean Air Act enforcement actions and disputes arising from the bankruptcy of Enron Corp. and related matters).
·	Our ability to constrain operation and maintenance costs.
·	Our ability to sell assets at acceptable prices and other acceptable terms.
·	The economic climate and growth in our service territory and changes in market demand and demographic patterns.
·	Inflationary and interest rate trends.
·	Our ability to develop and execute a strategy based on a view regarding prices of electricity, natural gas and other energy-related commodities.
·	Changes in the creditworthiness of the counterparties with whom we have contractual arrangements, including participants in the energy trading market.
·	Changes in the financial markets, particularly those affecting the availability of capital and our ability to refinance existing debt at attractive rates.
·	Actions of rating agencies, including changes in the ratings of debt.
·	Volatility and changes in markets for electricity, natural gas and other energy-related commodities.
·	Changes in utility regulation, including implementation of EPACT and membership in and integration into regional transmission structures.
·	Accounting pronouncements periodically issued by accounting standard-setting bodies.
·	The performance of our pension and other postretirement benefit plans.
·	Prices for power that we generate and sell at wholesale.
·	Changes in technology, particularly with respect to new, developing or alternative sources of generation.
·	Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes and other catastrophic events.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Regulatory Activity

Our significant regulatory activity progressed with the following major developments:

·	In January 2006, we implemented our Ohio Rate Stabilization Plans, resulting in increased revenues of $49 million for the three months ended March 31, 2006.
·	The Kentucky Public Service Commission approved our $41 million rate case settlement agreement. New rates became effective on March 30, 2006.
·	In March 2006, after the February 2006 receipt of an order in our Texas stranded costs proceeding, we filed with the Public Utility Commission of Texas (PUCT) for approval of a financing order to issue $1.8 billion in securitization bonds. We expect an order in June or July 2006.
·	In April 2006, the Public Utilities Commission of Ohio (PUCO) approved our recovery of the pre-construction costs for the Integrated Gasification Combined Cycle (IGCC) clean-coal plant in Meigs County, Ohio. The PUCO also ruled that it is reasonable to recover the pre-construction costs of the facility through a provider of last resort recovery mechanism. We subsequently submitted tariffs for PUCO approval related to recovery of our IGCC pre-construction costs.
·	In April 2006, we reached a tentative settlement in our APCo and WPCo rate case, subject to approval by the Public Service Commission of West Virginia, providing for a $44 million increase in rates effective July 28, 2006.
·	In May 2006, we filed a base rate case in Virginia requesting a net rate increase of $198 million.

Our near-term additional activity includes:

·	A TCC competition transition charge (CTC) filing with the PUCT in the second quarter to address a $491 million credit to customers from the True-up Proceeding.
·	Issuance of securitization bonds in Texas in the third quarter of 2006.

Fuel Costs

Market prices for coal, natural gas and oil continued increasing in the first quarter of 2006. These increasing fuel costs result from increasing worldwide demand, supply interruptions and uncertainty, anticipation and ultimate promulgation of clean air rules, transportation constraints and other market factors. We manage price and performance risk through a portfolio of contracts of varying durations and other fuel procurement and management activities. Fuel recovery mechanisms exist for about 55% of our fuel costs in our various jurisdictions. Additionally, about 25% of our fuel is used for off-system sales where prices for our power should allow us to recover our cost of fuel. Accordingly, we should recover approximately 80% of fuel cost increases. The remaining 20% of our fuel costs relate primarily to Ohio customers, where fuel is a fixed component of costs included in our rates, but we do not have an active fuel cost recovery adjustment mechanism. Such percentages are subject to change over time based on fuel cost impacts and changes to the recovery adjustment mechanisms at jurisdictions in our individual operating companies. In Indiana, our fuel recovery mechanism is temporarily capped, subject to preestablished escalators, at a fixed rate through June 2007. As a consequence of the cap, we currently expect under recoveries during 2006 and under-recovered $4 million for the quarter ended March 31, 2006. In West Virginia, we received permission to begin deferral accounting for over- or under-recovery of fuel and related costs effective July 1, 2006. In addition, our Ohio companies increased their generation rates in 2006, as previously approved by the PUCO in our Rate Stabilization Plans. While these items should help to offset some of the negative impact on our gross margins, we expect an additional eleven to thirteen percent increase in coal costs in 2006.

RESULTS OF OPERATIONS

Segments

Our principal operating business segments and their major activities were:

·	Utility Operations:
		Generation of electricity for sale to U.S. retail and wholesale customers.
		Electricity transmission and distribution in the U.S.
·	Investments - Other:
		Bulk commodity barging operations, wind farms, IPPs and other energy supply-related businesses.

Our consolidated Income Before Discontinued Operations for the three months ended March 31, 2006 and 2005 were as follows (Earnings and Weighted Average Basic Shares Outstanding in millions):

	2006						2005
	Earnings			EPS (c)			Earnings			EPS (c)
Utility Operations	$	365		$	0.93		$	353		$	0.90
Investments - Other		16			0.04			5			0.01
All Other (a)		(2	)		(0.01	)		(14	)		(0.04	)
Investments - Gas Operations (b)		(1	)		-			10			0.03
Income Before Discontinued Operations	$	378		$	0.96		$	354		$	0.90

Weighted Average Basic Shares Outstanding					394						393

(a)	All Other includes the parent company’s interest income and expense, as well as other nonallocated costs.
(b)	We sold our remaining gas pipeline and storage assets in 2005.
(c)	The earnings per share of any segment does not represent a direct legal interest in the assets and liabilities allocated to any one segment but rather represents a direct equity interest in AEP’s assets and liabilities as a whole.

First Quarter of 2006 Compared to First Quarter of 2005

Income Before Discontinued Operations in 2006 increased $24 million compared to 2005 due to increased utility operations revenue primarily related to rate increases in our Ohio jurisdiction as approved by the PUCO in CSPCo’s and OPCo’s Rate Stabilization Plans (RSP).

Our results of operations are discussed below according to our operating segments.

Utility Operations

Our Utility Operations include primarily regulated revenues with direct and variable offsetting expenses and net reported commodity trading operations. We believe that a discussion of the results from our Utility Operations segment on a gross margin basis is most appropriate. Gross margins represent utility operating revenues less the related direct cost of fuel, including consumption of chemicals and emissions allowances, and purchased power.

	Three Months Ended March 31,
	2006		2005
	(in millions)
Revenues	$	2,969	$	2,684
Fuel and Purchased Energy		1,127		923
Gross Margin		1,842		1,761
Depreciation and Amortization		333		318
Other Operating Expenses		846		805
Operating Income		663		638
Other Income (Expense), Net		42		30
Interest Expense and Preferred Stock Dividend Requirements		154		144
Income Tax Expense		186		171
Income Before Discontinued Operations	$	365	$	353

Summary of Selected Sales and Weather Data

For Utility Operations

For the Three Months Ended March 31, 2006 and 2005

	2006		2005
Energy Summary	(in millions of KWH)
Retail:
Residential		12,938		13,224
Commercial		8,909		8,732
Industrial		13,221		12,774
Miscellaneous		589		645
Subtotal		35,657		35,375
Texas Retail and Other		68		228
Total		35,725		35,603

Wholesale		10,844		12,635

Texas Wires Delivery		5,546		5,519

Cooling degree days and heating degree days are metrics commonly used in the utility industry as a measure of the impact of weather on results of operations. Cooling degree days and heating degree days in our service territory for the quarters ended March 31, 2006 and 2005 were as follows:

		2006	2005
Weather Summary		(in degree days)
Eastern Region
Actual - Heating (a)		1,456	1,774
Normal - Heating (b)		1,817	1,811

Actual - Cooling (c)		1	-
Normal - Cooling (b)		3	3

Western Region (d)
Actual - Heating (a)		658	769
Normal - Heating (b)		972	973

Actual - Cooling (c)		43	20
Normal - Cooling (b)		17	18

(a)	Eastern Region and Western Region heating degree days are calculated on a 55 degree temperature base.
(b)	Normal Heating/Cooling represents the 30-year average of degree days.
(c)	Eastern Region and Western Region cooling days are calculated on a 65 degree temperature base.
(d)	Western Region statistics represent PSO/SWEPCo customer base only.

First Quarter of 2006 Compared to First Quarter of 2005

Reconciliation of First Quarter of 2005 to First Quarter of 2006

Income from Utility Operations Before Discontinued Operations

(in millions)

First Quarter of 2005			$	353

Changes in Gross Margin:
Retail Margins	111
Off-system Sales	(24	)
Other	(6	)
Total Change in Gross Margin				81

Changes in Operating Expenses and Other:
Maintenance and Other Operation	6
Gain on Sales of Assets, Net	(46	)
Depreciation and Amortization	(15	)
Taxes Other Than Income Taxes	(1	)
Other Income (Expense), Net	12
Interest and Other Charges	(10	)
Total Change in Operating Expenses and Other				(54	)

Income Tax Expense				(15	)

First Quarter of 2006			$	365

Income from Utility Operations Before Discontinued Operations increased $12 million to $365 million in 2006. The key driver of the increase was an $81 million net increase in Gross Margin, offset in part by a $54 million increase in Operating Expenses and Other and a $15 million increase in Income Tax Expense.

The major components of the net increase in Gross Margin were as follows:

·	Retail Margins increased $111 million primarily due to the following:
·		A $49 million increase related to new rates implemented in our Ohio jurisdiction as approved by the PUCO in our RSPs;
·		A $28 million increase related to increased usage and customer growth in the industrial and commercial classes;
·		An $11 million increase related to increased usage and customer growth in the residential class; and
·		A $26 million increase related to increased sales to municipal, cooperative and other wholesale customers primarily as a result of new power supply contracts; partially offset by
·		A $25 million decrease in usage related to mild weather. As compared to the prior year, heating degree days were 18% lower in the east and 14% lower in the west.
·	Margins from Off-system Sales for 2006 were $24 million lower than in 2005 due to lower volumes in part from the sale of STP in May 2005 and lower optimization activities.
·	Other revenues decreased $6 million primarily due to a decrease in construction activities performed for third parties.

Utility Operating Expenses and Other changed between years as follows:

·	Maintenance and Other Operation expenses decreased $6 million primarily due to a decrease in construction activities performed for third parties.
·	Gain on Sales of Assets, Net decreased $46 million resulting from revenues related to the earnings sharing agreement with Centrica as stipulated in the purchase and sale agreement from the sale of our REPs in 2002. In 2005, we received $112 million related to two years of earnings sharing whereas in 2006 we received $70 million related to one year of earnings sharing.
·	Depreciation and Amortization expense increased $15 million primarily due to increased Ohio and Texas regulatory asset amortization.
·	Other Income (Expense), Net increased $12 million primarily due to capitalized carrying costs on environmental and system reliability capital expenditures for APCo. APCo began capitalizing carrying costs in conjunction with its environmental and reliability costs filing in Virginia in the third quarter of 2005.
·	Interest and Other Charges increased $10 million from the prior period primarily due to new debt issued during 2005 and increasing interest rates.
·	Income Tax Expense increased $15 million due to the increase in pretax income. See “AEP System Income Taxes” section below for further discussion of fluctuations related to income taxes.

Investments - Other

First Quarter of 2006 Compared to First Quarter of 2005

Income Before Discontinued Operations from our Investments - Other segment increased from $5 million in 2005 to $16 million in 2006. The increase was primarily due to favorable barging activity at AEP MEMCO LLC due to strong demand and a tight supply of barges which increased the barge fees. Additionally, the first quarter of 2006 operating conditions for our barging operations improved from 2005 when severe ice and flooding caused increased operating costs.

Other

Parent

First Quarter of 2006 Compared to First Quarter of 2005

The parent company’s loss decreased $12 million from 2005 primarily due to lower interest expense related to the redemption of $550 million senior unsecured notes in April 2005 and increased affiliated interest income related to favorable results from the corporate borrowing program.

Investments - Gas Operations

First Quarter of 2006 Compared to First Quarter of 2005

The $1 million Loss Before Discontinued Operations compares with $10 million of income recorded for 2005. Prior year results included one month of HPL’s operations due to the sale of HPL in January 2005. Current year results primarily relate to gas contracts that were not sold with the gas pipeline and storage assets.

AEP System Income Taxes

The increase in income tax expense of $17 million between the first quarter of 2006 and first quarter of 2005 is primarily due to an increase in pretax book income and changes in certain book/tax differences accounted for on a flow-through basis.

FINANCIAL CONDITION

We measure our financial condition by the strength of our balance sheet and the liquidity provided by our cash flows.

Debt and Equity Capitalization ($ in millions)

	March 31, 2006				December 31, 2005
Common Equity	$	9,384	43.0	%	$	9,088	42.5	%
Preferred Stock		61	0.3			61	0.3
Long-term Debt, including amounts due within one year		12,142	55.7			12,226	57.2
Short-term Debt		226	1.0			10	0.0

Total Debt and Equity Capitalization	$	21,813	100.0	%	$	21,385	100.0	%

Our common equity increased primarily due to earnings exceeding the amount of dividends paid in 2006. As a consequence of the capital changes during 2006, we improved our ratio of total debt to total capital from 57.2% to 56.7%.

The FASB’s current pension and postretirement benefit accounting project could have a major negative impact on our debt to capital ratio in future years. The potential change could require the recognition of an additional minimum liability for fully-funded pension and postretirement benefit plans, thereby eliminating on the balance sheet the SFAS 87 and SFAS 106 deferral and amortization of net actuarial gains and losses. If adopted, this could require recognition of a significant net of tax accumulated other comprehensive income reduction to common equity. We cannot predict the ultimate effects of the final rule or its effective date.

Liquidity

Liquidity, or access to cash, is an important factor in determining our financial stability. We are committed to maintaining adequate liquidity.

Credit Facilities

We manage our liquidity by maintaining adequate external financing commitments. At March 31, 2006, our available liquidity was approximately $2.7 billion as illustrated in the table below:

		Amount		Maturity
		(in millions)
Commercial Paper Backup:
	Revolving Credit Facility	$	1,000	May 2007
	Revolving Credit Facility		1,500	March 2010
Letter of Credit Facility			200	September 2006
Total			2,700
Cash and Cash Equivalents			276
Total Liquidity Sources			2,976
Less: AEP Commercial Paper Outstanding			215
	Letter of Credit Drawn on Credit Facility		31
Net Available Liquidity		$	2,730

In April 2006, we amended the terms and increased the size of our credit facilities from $2.7 billion to $3 billion on terms more economically favorable than the previous agreements. The amended facilities are structured as two $1.5 billion credit facilities, with an option in each to issue up to $200 million as letters of credit, expiring separately in March 2010 and April 2011. We also terminated an existing $200 million letter of credit facility. If the amendments had occurred prior to March 31, 2006 our Net Available Liquidity would have been $3,030 million.

Debt Covenants and Borrowing Limitations

Our revolving credit agreements contain certain covenants and require us to maintain our percentage of debt to total capitalization at a level that does not exceed 67.5%. The method for calculating our outstanding debt and other capital is contractually defined. At March 31, 2006, this contractually-defined percentage was 53.6%. Nonperformance of these covenants could result in an event of default under these credit agreements. At March 31, 2006, we complied with all of the covenants contained in these credit agreements. In addition, the acceleration of our payment obligations, or the obligations of certain of our subsidiaries, prior to maturity under any other agreement or instrument relating to debt outstanding in excess of $50 million would cause an event of default under these credit agreements and permit the lenders to declare the outstanding amounts payable.

We do not believe that our rights under the amended facilities would be affected by a material adverse change.

Under a regulatory order, our utility subsidiaries cannot incur additional indebtedness if the issuer’s common equity would constitute less than 30% (25% for TCC) of its capital. In addition, this order restricts the utility subsidiaries from issuing long-term debt unless that debt will be rated investment grade by at least one nationally recognized statistical rating organization. At March 31, 2006, all utility subsidiaries were in compliance with this order.

Utility Money Pool borrowings and external borrowings may not exceed amounts authorized by regulatory orders. At March 31, 2006, our utility subsidiaries had not exceeded those authorized limits.

Credit Ratings

AEP’s ratings have not been adjusted by any rating agency during 2006 and AEP is currently on a stable outlook by the rating agencies. Our current credit ratings are as follows:

	Moody’s	S&P	Fitch

AEP Short Term Debt	P-2	A-2	F-2
AEP Senior Unsecured Debt	Baa2	BBB	BBB

If we or any of our rated subsidiaries receive an upgrade from any of the rating agencies listed above, our borrowing costs could decrease. If we receive a downgrade in our credit ratings by one of the rating agencies listed above, our borrowing costs could increase and access to borrowed funds could be negatively affected.

Cash Flow

Our cash flows are a major factor in managing and maintaining our liquidity strength.

	Three Month Ended March 31,
	2006			2005
	(in millions)
Cash and Cash Equivalents at Beginning of Period	$	401		$	320
Net Cash Flows From Operating Activities		590			667
Net Cash Flows From (Used For) Investing Activities		(757	)		842
Net Cash Flows From (Used For) Financing Activities		42			(568	)
Net Increase (Decrease) in Cash and Cash Equivalents		(125	)		941
Cash and Cash Equivalents at End of Period	$	276		$	1,261

Cash from operations, combined with a bank-sponsored receivables purchase agreement and short-term borrowings, provides working capital and allows us to meet other short-term cash needs. We use our corporate borrowing program to meet the short-term borrowing needs of our subsidiaries. The corporate borrowing program includes a Utility Money Pool, which funds the utility subsidiaries, and a Nonutility Money Pool, which funds the majority of the nonutility subsidiaries. In addition, we also fund, as direct borrowers, the short-term debt requirements of other subsidiaries that are not participants in either money pool for regulatory or operational reasons. As of March 31, 2006, we had credit facilities totaling $2.5 billion to support our commercial paper program. In April 2006, we increased our credit facilities to $3 billion. We generally use short-term borrowings to fund working capital needs, property acquisitions and construction until long-term funding mechanisms are arranged. Sources of long-term funding include issuance of common stock or long-term debt and sale-leaseback or leasing agreements. Utility Money Pool borrowings and external borrowings may not exceed authorized limits under regulatory orders.

Operating Activities

	Three Months Ended March 31,
	2006			2005
	(in millions)
Net Income	$	381		$	355
Less: Income From Discontinued Operations		(3	)		(1	)
Income From Continuing Operations		378			354
Noncash Items Included in Earnings		317			325
Changes in Assets and Liabilities		(105	)		(12	)
Net Cash Flows From Operating Activities	$	590		$	667

2006 Operating Cash Flow

Net Cash Flows From Operating Activities were $590 million in 2006. We produced Income from Continuing Operations of $378 million. Income from Continuing Operations included noncash expense items primarily for depreciation, amortization, accretion, deferred taxes and deferred investment tax credits. In 2005, we initiated fuel proceedings in Oklahoma, Texas, Virginia and Arkansas seeking recovery of our increased fuel costs. Under-recovered fuel costs decreased due to recovery of higher cost of fuel, especially natural gas. Other changes in assets and liabilities represent items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant are a $99 million cash increase from net Accounts Receivable/Accounts Payable due to a lower balance of Customer Accounts Receivable at March 31, 2006 and an increase in Accrued Taxes of $176 million. We did not make a federal income tax payment during the first quarter of 2006.

2005 Operating Cash Flow

Net Cash Flows From Operating Activities were $667 million in 2005 consisting of our Income from Continuing Operations of $354 million and noncash charges of $327 million for Depreciation and Amortization. We realized gains of $115 million on sales of assets. Changes in Assets and Liabilities represent those items that had a current period cash flow impact, such as changes in working capital, as well as items that represent future rights or obligations to receive or pay cash, such as regulatory assets and liabilities. The current period activity in these asset and liability accounts relates to a number of items; the most significant is a $245 million increase in Accrued Taxes. We did not make a federal income tax payment during the first quarter of 2005.

Investing Activities

	Three Months Ended March 31,
	2006			2005
	(in millions)
Construction Expenditures	$	(772	)	$	(434	)
Change in Other Temporary Cash Investments, Net		27			(9	)
Investment Securities:
Purchases of Investment Securities		(2,469	)		(1,311	)
Sales of Investment Securities		2,380			1,396
Change in Investment Securities, Net		(89	)		85
Proceeds from Sales of Assets		111			1,184
Other		(34	)		16
Net Cash Flows From (Used for) Investing Activities	$	(757	)	$	842

Net Cash Flows Used For Investing Activities were $757 million in 2006 primarily due to Construction Expenditures. Construction Expenditures increased due to our environmental investment plan.

During 2006, we purchased $2.5 billion of investments and received $2.4 billion of proceeds from the sales of securities. During 2005, we purchased $1.3 billion of investments and received $1.4 billion of proceeds from the sales of securities. We purchase auction rate securities and variable rate demand notes with cash available for short-term investments. These amounts also include purchases and sales within our nuclear trusts.

Net Cash Flows From Investing Activities were $842 million in 2005 primarily due to the proceeds from the sale of HPL. During 2005, we sold HPL and used a portion of the proceeds from the sale to repurchase common stock. Our Construction Expenditures of $434 million included environmental, transmission and distribution investment.

We forecast $2.9 billion of Construction Expenditures for the remainder of 2006. 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, and the ability to access capital. These construction expenditures will be funded through results of operations and financing activities.

Financing Activities

	Three Months Ended March 31,
	2006			2005
	(in millions)
Issuance of Common Stock	$	5		$	17
Repurchase of Common Stock		-			(434	)
Issuance/Retirement of Debt, Net		129			65
Dividends Paid on Common Stock		(146	)		(138	)
Other		54			(78	)
Net Cash Flows From (Used for) Financing Activities	$	42		$	(568	)

Net Cash Flows From Financing Activities in 2006 were $42 million. During the first quarter of 2006, we issued $50 million of obligations relating to pollution control bonds and increased our short-term commercial paper outstanding. See Note 12 for a complete discussion of long-term debt issuances and retirements. The Other amount of $54 million in the above table primarily consists of $68 million received from a coal supplier related to a long-term coal purchase contract amended in March 2006.

Net Cash Flows Used For Financing Activities in 2005 were $568 million. During the first quarter of 2005, we repurchased common stock using a portion of the proceeds from the sale of HPL. In addition, our subsidiaries retired $66 million of cumulative preferred stock, which is reflected in the Other amount in the above table.

In April 2006, APCo issued $500 million of debt consisting of $250 million of 5.55% notes due 2011 and $250 million of 6.375% notes due 2036. Also in April, OPCo issued obligations relating to auction rate pollution control bonds in the amount of $65 million. The new bonds bear variable interest at a 28-day auction rate. The proceeds from this issuance will contribute to our investment in environmental equipment.

Off-balance Sheet Arrangements

Under a limited set of circumstances we enter into off-balance sheet arrangements to accelerate cash collections, reduce operational expenses and spread risk of loss to third parties. Our current guidelines restrict the use of off-balance sheet financing entities or structures to traditional operating lease arrangements and sales of customer accounts receivable that we enter in the normal course of business. Our off-balance sheet arrangements have not changed significantly from year-end. For complete information on each of these off-balance sheet arrangements see the “Off-balance Sheet Arrangements” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report.

Summary Obligation Information

A summary of our contractual obligations is included in our 2005 Annual Report and has not changed significantly from year-end other than the debt issuances and retirements discussed in “Cash Flow” “Financing Activities” above.

Other

Texas REPs

As part of the purchase and sale agreement related to the sale of our Texas REPs in 2002, we retained the right to share in earnings from the two REPs above a threshold amount through 2006 if the Texas retail market developed increased earnings opportunities. In March of 2006, we received a $70 million payment for our share in earnings for 2005. The payment for 2006 is contingent on Centrica’s future operating results, is capped at $20 million and, to the extent payable, will be paid in the first quarter of 2007. See “Texas REPs” section of Note 8.

SIGNIFICANT FACTORS

We continue to be involved in various matters described in the “Significant Factors” section of Management’s Financial Discussion and Analysis of Results of Operations in our 2005 Annual Report. The 2005 Annual Report should be read in conjunction with this report in order to understand significant factors without material changes in status since the issuance of our 2005 Annual Report, but may have a material impact on our future results of operations, cash flows and financial condition.

Texas Regulatory Activity

Texas Restructuring

The PUCT issued an order in TCC’s True-up Proceeding in February 2006, which determined that TCC’s true-up regulatory asset was $1.475 billion, which included carrying costs through September 2005. TCC filed an application in March 2006 requesting to securitize $1.8 billion of net stranded generation plant costs and related carrying costs to September 1, 2006. The $1.8 billion does not include TCC’s other true-up items, which are partially offsetting in nature. These obligations total $491 million and would be payable through a CTC over a period determined by the PUCT. Intervenors and the PUCT staff filed testimony in April 2006. Hearings are scheduled for May. It is possible that the PUCT could reduce the securitization amount by all or some portion of the negative other true-up items. If that occurs, a negative impact on the timing of cash flows could result. Cash flows from securitization would be adversely impacted if the PUCT reduces TCC’s computation of the amount to be securitized in the securitization proceeding.

The PUCT has not addressed the allocation of stranded costs to TCC’s wholesale jurisdiction. TCC estimates the amount allocated to wholesale to be less than $1 million, while intervenors and PUCT staff filed testimony recommending that $77 million of stranded costs be allocated to TCC’s wholesale jurisdiction. TCC cannot predict the ultimate amount the PUCT will allocate to the wholesale jurisdiction that TCC will not be able to securitize or recover.

Consistent with certain prior securitization determinations, the PUCT may deduct the cost-of-money benefit of accumulated deferred federal income taxes (ADFIT) from the securitization request. Then, the future cost-of-money benefit would be transferred to a separate regulatory asset recoverable in normal delivery rates outside of the securitization process, which would affect the timing of cash recovery. We estimate the total cost-of-money benefit to be $328 million, which TCC plans to include in its estimated CTC request. Intervenors filed testimony recommending an increase in this amount, along with the retrospective ADFIT amounts, by as much as $175 million.

In addition, the intervenors raised three issues totaling $138 million that were addressed by the PUCT in prior proceedings - the appropriate interest rate for both stranded cost and deferred fuel and the treatment of excess earnings refunds. Other issues raised by the intervenors dealt with the amounts to be securitized versus refunded to customers through the CTC, customer class allocation issues and debt defeasance strategies.

The difference between the recorded securitizable true-up regulatory asset of $1.5 billion at March 31, 2006 and our securitization request of $1.8 billion is detailed in the table below:

	(in millions)
Stranded Generation Plant Costs	$	969
Net Generation-related Regulatory Asset		249
Excess Earnings		(49	)
Recorded Net Stranded Generation Plant Costs		1,169
Recorded Debt Carrying Costs on Recorded Net Stranded Generation Plant Costs		284
Recorded Securitizable True-up Regulatory Asset		1,453
Unrecorded But Recoverable Equity Carrying Costs		212
Unrecorded Estimated April 2006 - August 2006 Debt Carrying Costs		40
Unrecorded Securitization Issuance Costs		24
Unrecorded Excess Earnings, Related Return and Other		75
Securitization Request	$	1,804

The principal components of the CTC rate reduction are an over-recovered fuel balance, the retail clawback and the ADFIT benefit related to TCC’s stranded generation cost, offset by a positive wholesale capacity auction true-up regulatory asset balance. TCC will incur carrying costs on the net negative other true-up regulatory liability balances until fully refunded. TCC anticipates filing to implement a negative CTC (as a rate reduction) for its net other true-up items in the second quarter of 2006.

The difference between the components of TCC’s recorded net regulatory liabilities - other true-up items as of March 31, 2006 and the amount expected to be requested in the CTC proceeding are detailed below:

	(in millions)
Wholesale Capacity Auction True-up	$	61
Carrying Costs on Wholesale Capacity Auction True-up		17
Retail Clawback		(61	)
Deferred Over-recovered Fuel Balance		(177	)
Recorded Net Regulatory Liabilities - Other True-up Items		(160	)
ADFIT Benefit		(328	)
Unrecorded Carrying Costs and Other		(3	)
Estimated CTC Request	$	(491	)

If we determine in future securitization and CTC proceedings that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and we are able to estimate the amount of such nonrecovery, we would record a provision for such amount which could have an adverse effect on future results of operations, cash flows and possibly financial condition. TCC intends to pursue rehearing and appeals to vigorously seek relief as necessary in both federal and state court where it believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. It is expected that the cities and other intervenors will also pursue vigorously court appeals to further reduce TCC’s true-up recoveries. Although TCC believes it has meritorious arguments, management cannot predict the ultimate outcome of any future proceedings, requested rehearings or court appeals. If the municipal customers and other intervenors succeed in their expected appeals, it could have a material adverse effect on future results of operations, cash flows and financial condition.

Litigation

In the ordinary course of business, we and our subsidiaries are involved in employment, commercial, environmental and regulatory litigation. Since it is difficult to predict the outcome of these proceedings, we cannot state what the eventual outcome of these proceedings will be, or what the timing of the amount of any loss, fine or penalty may be. Management does, however, assess the probability of loss for such contingencies and accrues a liability for cases that have a probable likelihood of loss and the loss amount can be estimated. For details on our pending litigation and regulatory proceedings see Note 4 - Rate Matters, Note 6 - Customer Choice and Industry Restructuring, Note 7 - Commitments and Contingencies and the “Litigation” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report. Additionally, see Note 3 - Rate Matters, Note 4 - Customer Choice and Industry Restructuring and Note 5 - Commitments and Contingencies included herein. An adverse result in these proceedings has the potential to materially affect the results of operations, cash flows and financial condition of AEP and its subsidiaries.

See discussion of the Environmental Litigation within the “Environmental Matters” section of “Significant Factors.”

Environmental Matters

We have committed to substantial capital investments and additional operational costs to comply with new environmental control requirements. The sources of these requirements include:

·	Requirements under the Clean Air Act (CAA) to reduce emissions of sulfur dioxide (SO₂), nitrogen oxide (NO_x), particulate matter (PM), and mercury from fossil fuel-fired power plants;
·	Requirements under the Clean Water Act (CWA) to reduce the impacts of water intake structures on aquatic species at certain of our power plants; and
·	Possible future requirements to reduce carbon dioxide (CO₂) emissions to address concerns about global climate change.

In addition, we are engaged in litigation with respect to certain environmental matters, have been notified of potential responsibility for the clean-up of contaminated sites, and incur costs for disposal of spent nuclear fuel and future decommissioning of our nuclear units. All of these matters are discussed in the “Environmental Matters” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report.

Clean Air Act Requirements

The CAA establishes a comprehensive program to protect and improve the nation’s air quality, and control mobile and stationary sources of air emissions. The major CAA programs affecting our power plants are briefly described below. Many of these programs are implemented and administered by the states, which can impose additional or more stringent requirements.

National Ambient Air Quality Standards: The CAA requires the Federal EPA to periodically review the available scientific data for six criteria pollutants and establish a concentration level in the ambient air for those substances that is adequate to protect the public health and welfare with an extra margin for safety. These concentration levels are known as “national ambient air quality standards” or NAAQS.

Each state identifies those areas within its boundaries that meet the NAAQS (attainment areas) and those that do not (nonattainment areas). Each state must then develop a state implementation plan (SIP) to bring nonattainment areas into compliance with the NAAQS and maintain good air quality in attainment areas. All SIPs are then submitted to the Federal EPA for approval. If a state fails to develop adequate plans, the Federal EPA must develop and implement a plan. In addition, as the Federal EPA reviews the NAAQS, the attainment status of areas can change, and states may be required to develop new SIPs. The Federal EPA recently proposed a new PM NAAQS and is conducting periodic reviews for additional criteria pollutants.

In 1997, the Federal EPA established new NAAQS that required further reductions in SO₂ and NO_x emissions. In 2005, the Federal EPA issued a final model federal rule, the Clean Air Interstate Rule (CAIR), that assists states developing new SIPs to meet the new NAAQS. CAIR reduces regional emissions of SO₂ and NO_x from power plants in the Eastern U.S. (29 states and the District of Columbia). CAIR requires power plants within these states to reduce emissions of SO₂ by 50 percent by 2010, and by 65 percent by 2015. NO_x emissions will be subject to additional limits beginning in 2009, and will be reduced by a total of 70 percent from current levels by 2015. Reduction of both SO₂ and NO_x would be achieved through a cap-and-trade program. The Federal EPA reconsidered and affirmed certain aspects of the final CAIR, and the rule has been challenged in the courts. States must develop and submit SIPs to implement CAIR by November 2006. Nearly all of the states in which our power plants are located will be covered by CAIR. Oklahoma is not affected, while Texas and Arkansas will be covered only by certain parts of CAIR. A SIP that complies with CAIR will also establish compliance with other CAA requirements, including certain visibility goals.

Hazardous Air Pollutants: As a result of the 1990 Amendments to the CAA, the Federal EPA investigated hazardous air pollutant (HAP) emissions from the electric utility sector and submitted a report to Congress, identifying mercury emissions from coal-fired power plants as warranting further study. In March 2005, the Federal EPA issued a final Clean Air Mercury Rule (CAMR) setting mercury standards for new coal-fired power plants and requiring all states to issue new SIPs including mercury requirements for existing coal-fired power plants. The Federal EPA issued a model federal rule based on a cap-and-trade program for mercury emissions from existing coal-fired power plants that would reduce mercury emissions to 38 tons per year from all existing plants in 2010, and to 15 tons per year in 2018. The national cap of 38 tons per year in 2010 is intended to reflect the level of reduction in mercury emissions that will be achieved as a result of installing controls to reduce SO₂ and NO_x emissions in order to comply with CAIR. The Federal EPA is currently reconsidering certain aspects of the final CAMR, and the rule has been challenged in the courts. States must develop and submit their SIPs to implement CAMR by November 2006.

The Acid Rain Program: The 1990 Amendments to the CAA included a cap-and-trade emission reduction program for SO₂ emissions from power plants, implemented in two phases. By 2000, the program established a nationwide cap on power plant SO₂ emissions of 8.9 million tons per year. The 1990 Amendments also contained requirements for power plants to reduce NO_x emissions through the use of available combustion controls.

The success of the SO₂ cap-and-trade program encouraged the Federal EPA and the states to use it as a model for other emission reduction programs, including CAIR and CAMR. We meet our obligations under the Acid Rain Program through the installation of controls, use of alternate fuels, and participation in the emissions allowance markets. CAIR uses the SO₂ allowances originally allocated through the Acid Rain Program as the basis for its SO₂ cap-and trade system.

Regional Haze: The CAA also establishes visibility goals for certain federally designated areas, including national parks, and requires states to submit SIPs that will demonstrate reasonable progress toward preventing impairment and remedying any existing impairment of visibility in these areas. This is commonly called the “Regional Haze” program. In June 2005, the Federal EPA issued its final Clean Air Visibility Rule (CAVR), detailing how the CAA’s best available retrofit technology (BART) requirements will be applied to facilities built between 1962 and 1977 that emit more than 250 tons per year of certain pollutants in specific industrial categories, including power plants. The final rule contains a demonstration that for power plants subject to CAIR, CAIR will result in more visibility improvements than BART would provide. Thus, states are allowed to substitute CAIR requirements in their Regional Haze SIPs for controls that would otherwise be required by BART. For BART-eligible facilities located in states not subject to CAIR requirements for SO₂and NO_x, some additional controls will be required. The final rule has been challenged in the courts.

Estimated Air Quality Environmental Investments

As discussed in the 2005 Annual Report, the CAIR and CAMR programs described above will require us to make significant additional investments, some of which are estimable. However, many of the rules described above are the subject of reconsideration by the Federal EPA, have been challenged in the courts and have not yet been incorporated into SIPs. As a result, these rules may be further modified. Our estimates disclosed in the 2005 Annual Report, are subject to significant uncertainties, and will be affected by any changes in the outcome of several interrelated variables and assumptions, including: the timing of implementation, required levels of reductions, methods for allocation of allowances and our selected compliance alternatives. In short, we cannot estimate our compliance costs with certainty.

We will seek recovery of expenditures for pollution control technologies, replacement or additional generation and associated operating costs from customers through our regulated rates (in regulated jurisdictions). We should be able to recover these expenditures through market prices in deregulated jurisdictions. If not, those costs could adversely affect future results of operations, cash flows and possibly financial condition.

Potential Regulation of CO₂ Emissions

At the Third Conference of the Parties to the United Nations Framework Convention on Climate Change held in Kyoto, Japan in December 1997, more than 160 countries, including the U.S., negotiated a treaty requiring legally-binding reductions in emissions of greenhouse gases, chiefly CO₂, which many scientists believe are contributing to global climate change. The U.S. signed the Kyoto Protocol in November 1998, but the treaty was not submitted to the Senate for its advice and consent. In March 2001, President Bush announced his opposition to the treaty. During 2004, enough countries ratified the treaty for it to become enforceable against the ratifying countries in February 2005. Several bills have been introduced in Congress seeking regulation of greenhouse gas emissions, including CO₂ emissions from power plants, but none has passed either house of Congress.

The Federal EPA stated that it does not have authority under the CAA to regulate greenhouse gas emissions that may affect global climate trends. This decision was challenged in the courts and upheld. A petition to appeal to the U.S. Supreme Court has been filed. While mandatory requirements to reduce CO₂ emissions at our power plants do not appear to be imminent, we participate in a number of voluntary programs to monitor, mitigate, and reduce greenhouse gas emissions.

Environmental Litigation

New Source Review (NSR) Litigation: In 1999, the Federal EPA and a number of states filed complaints alleging that APCo, CSPCo, I&M, and OPCo modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. A separate lawsuit, initiated by certain special interest groups, has been consolidated with the Federal EPA case. Several similar complaints were filed in 1999 and 2000 against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk. The alleged modifications at our power plants occurred over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has been completed, but no decision has been issued. A bench trial on remedy issues is scheduled for January 2007.

Courts that considered whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR, reached different conclusions. Similarly, courts that considered whether the activities at issue increased emissions from the power plants reached different results. Appeals on these and other issues have been filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court in one case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule and the Federal EPA filed a petition for rehearing in that case. The Federal EPA also recently proposed a rule that would define “emissions increases” in a way that most of the challenged activities would be excluded from NSR.

We are unable to estimate the loss or range of loss related to any contingent liability we might have for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the court. If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices for electricity. If we are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

Other Environmental Concerns

We perform environmental reviews and audits on a regular basis for the purpose of identifying, evaluating and addressing environmental concerns and issues. In addition to the matters discussed above, we are managing other environmental concerns that we do not believe are material or potentially material at this time. If they become significant or if any new matters arise that we believe could be material, they could have a material adverse effect on future results of operations, cash flows and possibly financial condition.

Critical Accounting Estimates

See the “Critical Accounting Estimates” section of “Management’s Financial Discussion and Analysis of Results of Operations” in the 2005 Annual Report for a discussion of the estimates and judgments required for regulatory accounting, revenue recognition, the valuation of long-lived assets, the accounting for pension and other postretirement benefits and the impact of new accounting pronouncements.

Adoption of New Accounting Pronouncements

Beginning in 2006, we adopted SFAS No. 123 (revised 2004) Share-Based Payment, on a modified prospective basis, resulting in an insignificant favorable cumulative effect of a change in accounting principle. Including stock-based compensation expense related to employee stock options and other share based awards, the trend in our quarter-over-quarter net income and earnings per share is not materially different. As of March 31, 2006, we have $46 million of total unrecognized compensation cost related to unvested share-based compensation arrangements. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.67 years. See Note 2 - New Accounting Pronouncements in our Condensed Notes to Condensed Consolidated Financial Statements for further discussion.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT RISK MANAGEMENT ACTIVITIES

Market Risks

As a major power producer and marketer of wholesale electricity, coal and emission allowances, our Utility Operations segment is exposed to certain market risks. These risks include commodity price risk, interest rate risk and credit risk. In addition, because we procure some services and materials in our energy business from foreign suppliers we have foreign currency risk. They represent the risk of loss that may impact us due to changes in the underlying market prices or rates.

Our Investment - Gas Operations segment holds forward gas contracts that were not sold with the gas pipeline and storage assets. These contracts are primarily financial derivatives, along with some physical contracts, which will gradually liquidate and completely expire in 2011. Our risk objective and outcomes to-date keep these positions risk neutral through maturity.

We employ risk management contracts including physical forward purchase and sale contracts, exchange futures and options, over-the-counter options, swaps and other derivative contracts to offset price risk where appropriate. We engage in risk management of electricity, gas, coal, and emissions and to a lesser degree other commodities associated with our energy business. As a result, we are subject to price risk. The amount of risk taken is controlled by risk management operations and our Chief Risk Officer and risk management staff. When risk management activities exceed certain predetermined limits, the positions are modified or hedged to reduce the risk to be within the limits unless specifically approved by the Risk Executive Committee.

We have policies and procedures that allow us to identify, assess, and manage market risk exposures in our day-to-day operations. Our risk policies are reviewed with our Board of Directors and approved by our Risk Executive Committee. Our Chief Risk Officer administers our risk policies and procedures. The Risk Executive Committee establishes risk limits, approves risk policies, and assigns responsibilities regarding the oversight and management of risk and monitors risk levels. Members of this committee receive various daily, weekly and/or monthly reports regarding compliance with policies, limits and procedures. Our committee meets monthly and consists of the Chief Risk Officer, senior executives, and other senior financial and operating managers.

We actively participate in the Committee of Chief Risk Officers (CCRO) to develop standard disclosures for risk management activities around risk management contracts. The CCRO is composed of the chief risk officers of major electricity and gas companies in the United States. The CCRO adopted disclosure standards for risk management contracts to improve clarity, understanding and consistency of information reported. Implementation of the disclosures is voluntary. We support the work of the CCRO and have embraced the disclosure standards applicable to our business activities. The following tables provide information on our risk management activities.

Mark-to-Market Risk Management Contract Net Assets (Liabilities)

The following two tables summarize the various mark-to-market (MTM) positions included in our condensed balance sheet as of March 31, 2006 and the reasons for changes in our total MTM value included in our condensed balance sheet as compared to December 31, 2005.

Reconciliation of MTM Risk Management Contracts to

Condensed Consolidated Balance Sheet

March 31, 2006

(in millions)

	Utility Operations			Investments - Gas Operations			Sub-Total MTM Risk Management Contracts			PLUS: MTM of Cash Flow and Fair Value Hedges			Total
Current Assets	$	437		$	134		$	571		$	54		$	625
Noncurrent Assets		449			199			648			7			655
Total Assets		886			333			1,219			61			1,280

Current Liabilities		(379	)		(139	)		(518	)		(21	)		(539	)
Noncurrent Liabilities		(293	)		(204	)		(497	)		(3	)		(500	)
Total Liabilities		(672	)		(343	)		(1,015	)		(24	)		(1,039	)

Total MTM Derivative Contract Net Assets (Liabilities)	$	214		$	(10	)	$	204		$	37		$	241

MTM Risk Management Contract Net Assets (Liabilities)

Three Months Ended March 31, 2006

(in millions)

	Utility Operations			Investments-Gas Operations			Total
Total MTM Risk Management Contract Net Assets (Liabilities) at December 31, 2005	$	215		$	(19	)	$	196
(Gain) Loss from Contracts Realized/Settled During the Period and Entered in a Prior Period		(5	)		7			2
Fair Value of New Contracts at Inception When Entered During the Period (a)		1			-			1
Net Option Premiums Paid/(Received) for Unexercised or Unexpired Option Contracts Entered During The Period		(4	)		-			(4	)
Changes in Fair Value Due to Valuation Methodology Changes on Forward Contracts		1			-			1
Changes in Fair Value due to Market Fluctuations During the Period (b)		8			2			10
Changes in Fair Value Allocated to Regulated Jurisdictions (c)		(2	)		-			(2	)
Total MTM Risk Management Contract Net Assets (Liabilities) at March 31, 2006	$	214		$	(10	)		204
Net Cash Flow and Fair Value Hedge Contracts								37
Ending Net Risk Management Assets at March 31, 2006							$	241

(a)	Most of the fair value comes from longer term fixed price contracts with customers that seek to limit their risk against fluctuating energy prices. Inception value is only recorded if observable market data can be obtained for valuation inputs for the entire contract term. The contract prices are valued against market curves associated with the delivery location and delivery term.
(b)	Market fluctuations are attributable to various factors such as supply/demand, weather, storage, etc.
(c)	“Change in Fair Value Allocated to Regulated Jurisdictions” relates to the net gains (losses) of those contracts that are not reflected in the Condensed Consolidated Statements of Operations. These net gains (losses) are recorded as regulatory assets/liabilities for those subsidiaries that operate in regulated jurisdictions.

Maturity and Source of Fair Value of MTM Risk Management Contract Net Assets (Liabilities)

The following table presents:

·	The method of measuring fair value used in determining the carrying amount of our total MTM asset or liability (external sources or modeled internally).
·	The maturity, by year, of our net assets/liabilities, giving an indication of when these MTM amounts will settle and generate cash.

Maturity and Source of Fair Value of MTM

Risk Management Contract Net Assets (Liabilities)

Fair Value of Contracts as of March 31, 2006

(in millions)

	Remainder 2006			2007			2008			2009			2010			After 2010		Total
Utility Operations:
Prices Actively Quoted - Exchange Traded Contracts	$	38		$	(1	)	$	3		$	-		$	-		$	-	$	40
Prices Provided by Other External Sources - OTC Broker Quotes (a)		13			39			28			23			-			-		103
Prices Based on Models and Other Valuation Methods (b)		(7	)		17			14			14			29			4		71
Total	$	44		$	55		$	45		$	37		$	29		$	4	$	214

Investments - Gas Operations:
Prices Actively Quoted - Exchange Traded Contracts	$	(3	)	$	12		$	-		$	-		$	-		$	-	$	9
Prices Provided by Other External Sources - OTC Broker Quotes (a)		(1	)		(9	)		-			-			-			-		(10	)
Prices Based on Models and Other Valuation Methods (b)		(2	)		-			(1	)		(4	)		(3	)		1		(9	)
Total	$	(6	)	$	3		$	(1	)	$	(4	)	$	(3	)	$	1	$	(10	)

Total:
Prices Actively Quoted - Exchange Traded Contracts	$	35		$	11		$	3		$	-		$	-		$	-	$	49
Prices Provided by Other External Sources - OTC Broker Quotes (a)		12			30			28			23			-			-		93
Prices Based on Models and Other Valuation Methods (b)		(9	)		17			13			10			26			5		62
Total	$	38		$	58		$	44		$	33		$	26		$	5	$	204

(a)

Prices Provided by Other External Sources - OTC Broker Quotes reflects information obtained from over-the-counter (OTC) brokers, industry services, or multiple-party on-line platforms.

(b)

Prices Based on Models and Other Valuation Methods is in the absence of pricing information from external sources. Modeled information is derived using valuation models developed by the reporting entity, reflecting when appropriate, option pricing theory, discounted cash flow concepts, valuation adjustments, etc. and may require projection of prices for underlying commodities beyond the period that prices are available from third-party sources. In addition, where external pricing information or market liquidity is limited, such valuations are classified as modeled.

The determination of the point at which a market is no longer liquid for placing it in the Modeled category in the preceding table varies by market. The following table reports an estimate of the maximum tenors (contract maturities) of the liquid portion of each energy market.

Maximum Tenor of the Liquid Portion of Risk Management Contracts

As of March 31, 2006

Commodity	Transaction Class	Market/Region	Tenor
			(in Months)
Natural Gas	Futures	NYMEX / Henry Hub	60
	Physical Forwards	Gulf Coast, Texas	21
	Swaps	Northeast, Mid-Continent, Gulf Coast, Texas	21
	Exchange Option Volatility	NYMEX / Henry Hub	12
Power	Futures	AEP East - PJM	36
	Physical Forwards	AEP East	45
	Physical Forwards	AEP West	45
	Physical Forwards	West Coast	45
	Peak Power Volatility (Options)	AEP East - Cinergy, PJM	12
Emissions	Credits	SO₂, NO_x	33
Coal	Physical Forwards	PRB, NYMEX, CSX	33

Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss) (AOCI) on the Condensed Consolidated Balance Sheets

We are exposed to market fluctuations in energy commodity prices impacting our power and remaining gas operations. We monitor these risks on our future operations and may employ various commodity instruments and cash flow hedges to mitigate the impact of these fluctuations on the future cash flows from assets. We do not hedge all commodity price risk.

We employ the use of interest rate derivative transactions to manage interest rate risk related to existing variable rate debt and to manage interest rate exposure on anticipated borrowings of fixed-rate debt. We do not hedge all interest rate exposure.

The following table provides the detail on designated, effective cash flow hedges included in AOCI on our Condensed Consolidated Balance Sheets and the reasons for changes in cash flow hedges from December 31, 2005 to March 31, 2006. The following table also indicates what portion of designated, effective hedges are expected to be reclassified into net income in the next 12 months. Only contracts designated as effective cash flow hedges are recorded in AOCI. Therefore, economic hedge contracts that are not designated as effective cash flow hedges are marked-to-market and are included in the previous risk management tables.

Total Accumulated Other Comprehensive Income (Loss) Activity for Cash Flow Hedges

Three Months Ended March 31, 2006

(in millions)

	Power and Gas			Interest Rate			Total
Beginning Balance in AOCI, December 31, 2005	$	(6	)	$	(21	)	$	(27	)
Changes in Fair Value		22			9			31
Reclassifications from AOCI to Net Income for Cash Flow Hedges Settled		3			1			4
Ending Balance in AOCI, March 31, 2006	$	19		$	(11	)	$	8

After Tax Portion Expected to be Reclassified to Earnings During Next 12 Months	$	18		$	(1	)	$	17

Credit Risk

We limit credit risk in our marketing and trading activities by assessing creditworthiness of potential counterparties before entering into transactions with them and continuing to evaluate their creditworthiness after transactions have been initiated. Only after an entity has met our internal credit rating criteria will we extend unsecured credit. We use Moody’s Investors Service, Standard & Poor’s and qualitative and quantitative data to assess the financial health of counterparties on an ongoing basis. We use our analysis, in conjunction with the rating agencies’ information, to determine appropriate risk parameters. We also require cash deposits, letters of credit and parental/affiliate guarantees as security from counterparties depending upon credit quality in our normal course of business.

We have risk management contracts with numerous counterparties. Since open risk management contracts are valued based on changes in market prices of the related commodities, our exposures change daily. As of March 31, 2006, our credit exposure net of credit collateral to sub investment grade counterparties was approximately 3.13%, expressed in terms of net MTM assets and net receivables. As of March 31, 2006, the following table approximates our counterparty credit quality and exposure based on netting across commodities, instruments and legal entities where applicable (in millions, except number of counterparties):

Counterparty Credit Quality	Exposure Before Credit Collateral		Credit Collateral		Net Exposure		Number of Counterparties >10%		Net Exposure of Counterparties >10%
Investment Grade	$	807	$	145	$	662		1	$	87
Split Rating		4		2		2		2		2
Noninvestment Grade		134		125		9		1		8
No External Ratings:
Internal Investment Grade		85		-		85		1		64
Internal Noninvestment Grade		32		17		15		2		14
Total	$	1,062	$	289	$	773		7	$	175

Generation Plant Hedging Information

This table provides information on operating measures regarding the proportion of output of our generation facilities (based on economic availability projections) economically hedged, including both contracts designated as cash flow hedges under SFAS 133 and contracts not designated as cash flow hedges. This information is forward-looking and provided on a prospective basis through December 31, 2008. Please note that this table is a point-in-time estimate, subject to changes in market conditions and our decisions on how to manage operations and risk. “Estimated Plant Output Hedged” represents the portion of MWHs of future generation/production, taking into consideration scheduled plant outages, for which we have sales commitments or estimated requirement obligations to customers.

Generation Plant Hedging Information

Estimated Next Three Years

As of March 31, 2006

	Remainder 2006	2007	2008
Estimated Plant Output Hedged	90%	91%	92%

VaR Associated with Risk Management Contracts

Commodity Price Risk

We use a risk measurement model, which calculates Value at Risk (VaR) to measure our commodity price risk in the risk management portfolio. The VaR is based on the variance-covariance method using historical prices to estimate volatilities and correlations and assumes a 95% confidence level and a one-day holding period. Based on this VaR analysis, at March 31, 2006, a near term typical change in commodity prices is not expected to have a material effect on our results of operations, cash flows or financial condition.

The following table shows the end, high, average, and low market risk as measured by VaR for the periods indicated:

VaR Model

Three Months Ended March 31, 2006				Twelve Months Ended December 31, 2005
(in millions)				(in millions)
End	High	Average	Low	End	High	Average	Low
$2	$6	$3	$2	$3	$5	$3	$1

Interest Rate Risk

We utilize a VaR model to measure interest rate market risk exposure. The interest rate VaR model is based on a Monte Carlo simulation with a 95% confidence level and a one-year holding period. The volatilities and correlations were based on three years of daily prices. The risk of potential loss in fair value attributable to our exposure to interest rates, primarily related to long-term debt with fixed interest rates, was $531 million at March 31, 2006 and $615 million at December 31, 2005. We would not expect to liquidate our entire debt portfolio in a one-year holding period. Therefore, a near term change in interest rates should not materially affect our results of operations, cash flows or financial position.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

For the Three Months Ended March 31, 2006 and 2005

(in millions, except per-share amounts)

(Unaudited)

	2006			2005
REVENUES
Utility Operations	$	2,987		$	2,605
Gas Operations		(18	)		357
Other		139			103
TOTAL		3,108			3,065

EXPENSES
Fuel and Other Consumables Used for Electric Generation		961			789
Purchased Energy for Resale		166			130
Purchased Gas for Resale		-			249
Maintenance and Other Operation		828			837
Gain/Loss on Disposition of Assets, Net		(68	)		(115	)
Depreciation and Amortization		341			327
Taxes Other Than Income Taxes		191			188
TOTAL		2,419			2,405

OPERATING INCOME		689			660

Interest and Investment Income		8			11
Carrying Costs Income		30			20
Allowance For Equity Funds Used During Construction		6			6
Gain on Disposition of Equity Investments, Net		3			-

INTEREST AND OTHER CHARGES
Interest Expense		168			173
Preferred Stock Dividend Requirements of Subsidiaries		1			2
TOTAL		169			175

INCOME BEFORE INCOME TAX EXPENSE, MINORITY INTEREST EXPENSE AND EQUITY EARNINGS		567			522

Income Tax Expense		189			172
Minority Interest Expense		-			1
Equity Earnings of Unconsolidated Subsidiaries		-			5

INCOME BEFORE DISCONTINUED OPERATIONS		378			354

DISCONTINUED OPERATIONS, Net of Tax		3			1

NET INCOME	$	381		$	355

WEIGHTED AVERAGE NUMBER OF BASIC SHARES OUTSTANDING		394			393

BASIC EARNINGS PER SHARE
Income Before Discontinued Operations	$	0.96		$	0.90
Discontinued Operations, Net of Tax		0.01			-
TOTAL BASIC EARNINGS PER SHARE	$	0.97		$	0.90

WEIGHTED AVERAGE NUMBER OF DILUTED SHARES OUTSTANDING		396			394

DILUTED EARNINGS PER SHARE
Income Before Discontinued Operations	$	0.95		$	0.90
Discontinued Operations, Net of Tax		0.01			-
TOTAL DILUTED EARNINGS PER SHARE	$	0.96		$	0.90

CASH DIVIDENDS PAID PER SHARE	$	0.37		$	0.35

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

ASSETS

March 31, 2006 and December 31, 2005

(in millions)

(Unaudited)

	2006			2005
CURRENT ASSETS
Cash and Cash Equivalents	$	276		$	401
Other Temporary Cash Investments		202			127
Accounts Receivable:
Customers		673			826
Accrued Unbilled Revenues		315			374
Miscellaneous		45			51
Allowance for Uncollectible Accounts		(33	)		(31	)
Total Receivables		1,000			1,220
Fuel, Materials and Supplies		776			726
Risk Management Assets		625			926
Margin Deposits		171			221
Regulatory Asset for Under-Recovered Fuel Costs		92			197
Other		107			127
TOTAL		3,249			3,945

PROPERTY, PLANT AND EQUIPMENT
Electric:
Production		16,726			16,653
Transmission		6,477			6,433
Distribution		10,895			10,702
Other (including gas, coal mining and nuclear fuel)		3,146			3,116
Construction Work in Progress		2,538			2,217
Total		39,782			39,121
Accumulated Depreciation and Amortization		14,974			14,837
TOTAL - NET		24,808			24,284

OTHER NONCURRENT ASSETS
Regulatory Assets		3,213			3,262
Securitized Transition Assets and Other		583			593
Spent Nuclear Fuel and Decommissioning Trusts		1,160			1,134
Investments in Power and Distribution Projects		47			97
Goodwill		76			76
Long-term Risk Management Assets		655			886
Employee Benefits and Pension Assets		1,090			1,105
Other		840			746
TOTAL		7,664			7,899

Assets Held for Sale		44			44

TOTAL ASSETS	$	35,765		$	36,172

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED BALANCE SHEETS

LIABILITIES AND SHAREHOLDERS’ EQUITY

March 31, 2006 and December 31, 2005

(Unaudited)

			2006		2005
CURRENT LIABILITIES			(in millions)
Accounts Payable			$	1,033	$	1,144
Short-term Debt				226		10
Long-term Debt Due Within One Year				1,061		1,153
Risk Management Liabilities				539		906
Accrued Taxes				829		651
Accrued Interest				180		183
Customer Deposits				415		571
Other				581		842
TOTAL				4,864		5,460

NONCURRENT LIABILITIES
Long-term Debt				11,081		11,073
Long-term Risk Management Liabilities				500		723
Deferred Income Taxes				4,847		4,810
Regulatory Liabilities and Deferred Investment Tax Credits				2,760		2,747
Asset Retirement Obligations				950		936
Employee Benefits and Pension Obligations				342		355
Deferred Gain on Sale and Leaseback - Rockport Plant Unit 2				155		157
Deferred Credits and Other				821		762
TOTAL				21,456		21,563

TOTAL LIABILITIES				26,320		27,023

Cumulative Preferred Stock Not Subject to Mandatory Redemption				61		61

Commitments and Contingencies (Note 5)

COMMON SHAREHOLDERS’ EQUITY
Common Stock Par Value $6.50:
	2006	2005
Shares Authorized	600,000,000	600,000,000
Shares Issued	415,412,203	415,218,830
(21,499,992 shares were held in treasury at March 31, 2006 and December 31, 2005)				2,700		2,699
Paid-in Capital				4,137		4,131
Retained Earnings				2,520		2,285
Accumulated Other Comprehensive Income (Loss)				27		(27	)
TOTAL				9,384		9,088

TOTAL LIABILITIES AND SHAREHOLDERS’ EQUITY			$	35,765	$	36,172

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended March 31, 2006 and 2005

(in millions)

(Unaudited)

	2006			2005
OPERATING ACTIVITIES
Net Income	$	381		$	355
Less: Income from Discontinued Operations		(3	)		(1	)
Income from Continuing Operations		378			354
Adjustments for Noncash Items:
Depreciation and Amortization		341			327
Accretion of Asset Retirement Obligations		15			18
Deferred Income Taxes		7			(19	)
Deferred Investment Tax Credits		(7	)		(8	)
Carrying Costs Income		(30	)		(20	)
Mark-to-Market of Risk Management Contracts		(9	)		27
Deferred Property Taxes		(82	)		(82	)
Pension Contributions to Qualified Plan Trusts		-			(102	)
Fuel Under-Recovery		103			52
Gain on Sales of Assets and Equity Investments, Net		(71	)		(115	)
Change in Other Noncurrent Assets		73			(60	)
Change in Other Noncurrent Liabilities		(5	)		(45	)
Changes in Certain Components of Working Capital:
Accounts Receivable, Net		214			104
Fuel, Materials and Supplies		(50	)		64
Accounts Payable		(115	)		7
Accrued Taxes		176			245
Customer Deposits		(157	)		55
Other Current Assets		69			(8	)
Other Current Liabilities		(260	)		(127	)
Net Cash Flows From Operating Activities		590			667

INVESTING ACTIVITIES
Construction Expenditures		(772	)		(434	)
Change in Other Temporary Cash Investments, Net		27			(9	)
Purchases of Investment Securities		(2,469	)		(1,311	)
Sales of Investment Securities		2,380			1,396
Proceeds from Sales of Assets		111			1,184
Other		(34	)		16
Net Cash Flows From (Used For) Investing Activities		(757	)		842

FINANCING ACTIVITIES
Issuance of Common Stock		5			17
Repurchase of Common Stock		-			(434	)
Change in Short-term Debt, Net		216			(5	)
Issuance of Long-term Debt		55			580
Retirement of Long-term Debt		(142	)		(510	)
Dividends Paid on Common Stock		(146	)		(138	)
Other		54			(78	)
Net Cash Flows From (Used For) Financing Activities		42			(568	)

Net Increase (Decrease) in Cash and Cash Equivalents		(125	)		941
Cash and Cash Equivalents at Beginning of Period		401			320
Cash and Cash Equivalents at End of Period	$	276		$	1,261

SUPPLEMENTARY INFORMATION
Cash paid for interest (net of capitalized amounts)	$	159		$	170
Cash paid (received) for income taxes, net of refunds		13			(57	)
Noncash acquisitions under capital leases		20			9
Construction Expenditures Included in Accounts Payable at March 31,		246			146

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN COMMON SHAREHOLDERS’ EQUITY AND

COMPREHENSIVE INCOME (LOSS)

For the Three Months Ended March 31, 2006 and 2005

(in millions)

(Unaudited)

		Common Stock										Accumulated Other Comprehensive Income (Loss)
		Shares		Amount		Paid-in Capital			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total
DECEMBER 31, 2004			405	$	2,632	$	4,203		$	2,024		$	(344	)	$	8,515
Issuance of Common Stock					3		14									17
Common Stock Dividends										(138	)					(138	)
Repurchase of Common Stock							(434	)								(434	)
Other							3									3
TOTAL																7,963

COMPREHENSIVE INCOME
Other Comprehensive Income (Loss), Net of Tax:
	Foreign Currency Translation Adjustments, Net of Tax of $0												1			1
	Cash Flow Hedges, Net of Tax of $28												(51	)		(51	)
NET INCOME										355						355
TOTAL COMPREHENSIVE INCOME																305
MARCH 31, 2005			405	$	2,635	$	3,786		$	2,241		$	(394	)	$	8,268

DECEMBER 31, 2005			415	$	2,699	$	4,131		$	2,285		$	(27	)	$	9,088
Issuance of Common Stock					1		4									5
Common Stock Dividends										(146	)					(146	)
Other							2									2
TOTAL																8,949

COMPREHENSIVE INCOME
Other Comprehensive Income, Net of Tax:
	Cash Flow Hedges, Net of Tax of $19												35			35
	Securities Available for Sale, Net of Tax of $10												19			19
NET INCOME										381						381
TOTAL COMPREHENSIVE INCOME																435
MARCH 31, 2006			415	$	2,700	$	4,137		$	2,520		$	27		$	9,384

See Condensed Notes to Condensed Consolidated Financial Statements.

AMERICAN ELECTRIC POWER, INC. AND SUBSIDIARY COMPANIES

INDEX TO CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1.	Significant Accounting Matters
2.	New Accounting Pronouncements
3.	Rate Matters
4.	Customer Choice and Industry Restructuring
5.	Commitments and Contingencies
6.	Guarantees
7.	Company-wide Staffing and Budget Review
8.	Dispositions, Discontinued Operations and Assets Held for Sale
9.	Benefit Plans
10.	Stock-Based Compensation
11.	Business Segments
12.	Financing Activities

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES

CONDENSED NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. SIGNIFICANT ACCOUNTING MATTERS

General

The accompanying unaudited interim financial statements should be read in conjunction with the 2005 Annual Report as incorporated in and filed with our 2005 Form 10-K.

In the opinion of management, the unaudited interim financial statements reflect all normal and recurring accruals and adjustments that are necessary for a fair presentation of our results of operations for interim periods.

Components of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss) is included on our Condensed Consolidated Balance Sheets in the common shareholders’ equity section. The following table provides the components that constitute the balance sheet amount in Accumulated Other Comprehensive Income (Loss):

	March 31,			December 31,
	2006			2005
Components	(in millions)
Securities Available for Sale, Net of Tax	$	38		$	19
Cash Flow Hedges, Net of Tax		8			(27	)
Minimum Pension Liability, Net of Tax		(19	)		(19	)
Total	$	27		$	(27	)

At March 31, 2006, we expect to reclassify approximately $17 million of net losses from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to Net Income during the next twelve months at the time the hedged transactions affect Net Income. The actual amounts that are reclassified from Accumulated Other Comprehensive Income (Loss) to Net Income can differ as a result of market fluctuations. Twenty-one months is the maximum length of time that we hedge our exposure to variability in future cash flows with contracts designated as cash flow hedges.

Stock-Based Compensation Plans

At March 31, 2006, we have options outstanding under two stock-based employee compensation plans: The Amended and Restated American Electric Power System Long-Term Incentive Plan and the Central and South West Corporation Long-Term Incentive Plan. We also grant performance share units, phantom stock units, restricted shares and restricted stock units to employees.

On January 1, 2006, we adopted SFAS No. 123 (revised 2004), “Share-Based Payment,” (SFAS 123R) which requires the measurement and recognition of compensation expense for all share-based payment awards made to employees and directors including stock options and employee stock purchases based on estimated fair values. See the SFAS 123 (revised 2004) “Share-Based Payment” section of Note 2 for additional discussion.

In conjunction with the adoption of SFAS 123R, we changed our method of attributing the value of stock-based compensation to expense from the accelerated multiple-option approach to the straight-line single-option method. Compensation expense for all share-based payment awards granted prior to January 1, 2006 will continue to be recognized using the accelerated multiple-option approach while compensation expense for all share-based payment awards granted on or after January 1, 2006 is recognized using the straight-line single-option method. As stock-based compensation expense recognized in our Condensed Consolidated Statements of Operations for the first quarter of 2006 is based on awards ultimately expected to vest, it has been reduced for estimated forfeitures. SFAS 123R requires forfeitures to be estimated at the time of grant and revised, if necessary, in subsequent periods if actual forfeitures differ from those estimates. In our pro forma information presented below as required under SFAS 123 for the periods prior to 2006, we accounted for forfeitures as they occurred.

For the quarter ended March 31, 2005, no stock option expense was reflected in Net Income as we accounted for stock options using the intrinsic value method under Accounting Principles Board (APB) Opinion No. 25, “Accounting For Stock Issued to Employees.” Under the intrinsic value method, no stock option expense is recognized when the exercise price of the stock options granted equals the fair value of the underlying stock at the date of grant. No options were granted during the first quarter of 2005. For the quarters ended March 31, 2006 and 2005, compensation cost is included in Net Income for the performance share units, phantom stock units, restricted shares, restricted stock units and the Director’s stock units. See Note 10 for additional discussion.

Pro Forma Information Under SFAS 123, “Accounting for Stock-Based Compensation,” for Periods Presented Prior to January 1, 2006

The following table shows the effect on our Net Income and Earnings Per Share as if we had applied fair value measurement and recognition provisions of SFAS 123 to stock-based employee and director compensation awards for the three months ended March 31, 2005:

	2005
	(in millions, except per share data)
Net Income, as reported	$	355
Add: Stock-based compensation expense included in reported Net Income, net of related tax effects		2
Deduct: Stock-based compensation expense determined under fair value based method for all awards, net of related tax effects		(2	)
Pro Forma Net Income	$	355

Earnings Per Share:
Basic - as Reported	$	0.90
Basic - Pro Forma (a)	$	0.90

Diluted - as Reported	$	0.90
Diluted - Pro Forma (a)	$	0.90

(a)	The pro forma amounts are not representative of the effects on reported net income for future years.

Earnings Per Share (EPS)

The following table presents our basic and diluted Earnings Per Share (EPS) calculations included in our Condensed Consolidated Statements of Operations:

	Three Months Ended March 31,
	2006					2005
	(in millions, except per share data)
			$/share					$/share
Earnings applicable to common stock	$	381				$	355

Average number of basic shares outstanding		393.7	$	0.97			393.1	$	0.90
Average dilutive effect of:
Performance Share Units		1.4		(0.01	)		0.8		-
Stock Options		0.3		-			0.3		-
Restricted Stock Units		0.1		-			-		-
Restricted Shares		0.1		-			-		-
Average number of diluted shares outstanding		395.6	$	0.96			394.2	$	0.90

Our stock option and other equity compensation plans are discussed in Note 10.

Related Party Transactions

	Three Months Ended March 31,
	2006		2005
	(in millions)
AEP Consolidated Purchased Energy:
Ohio Valley Electric Corporation (43.47% Owned)	$	55	$	43
Sweeny Cogeneration Limited Partnership (50% Owned)		34		29
AEP Consolidated Other Revenues - Barging and Other Transportation Services - Ohio Valley Electric Corporation (43.47% Owned)		7		4

Reclassifications

Certain prior period financial statement items have been reclassified to conform to current period presentation.

On our Condensed Consolidated Statements of Cash Flows, we included purchases and sales of investments within our Spent Nuclear Fuel and Decommissioning Trusts as a component of Investing Activities.

These revisions had no impact on our previously reported results of operations, financial condition or changes in shareholders’ equity.

2. 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 new pronouncements issued or implemented in 2006 that we have determined relate to our operations.

SFAS 123 (revised 2004) “Share-Based Payment”

In December 2004, the FASB issued SFAS 123R. SFAS 123R requires entities to recognize compensation expense in an amount equal to the fair value of share-based payments granted to employees. The statement eliminates the alternative to use the intrinsic value method of accounting previously available under APB Opinion No. 25, “Accounting for Stock Issued to Employees.” We recorded an insignificant cumulative effect of a change in accounting principle in the first quarter of 2006 for the effect of initially applying the statement primarily reflected in Maintenance and Other Operation on our Condensed Consolidated Statements of Operation.

In March 2005, the SEC issued Staff Accounting Bulletin No. 107, “Share-Based Payment” (SAB 107), which conveys the SEC staff’s views on the interaction between SFAS 123R and certain SEC rules and regulations. SAB 107 also provides the SEC staff’s views regarding the valuation of share-based payment arrangements for public companies. Also, the FASB issued three FASB Staff Positions (FSP) during 2005 and one in February 2006 that provided additional implementation guidance. We applied the principles of SAB 107 and the applicable FSPs in conjunction with our adoption of SFAS 123R.

We adopted SFAS 123R in the first quarter of 2006 using the modified prospective method. This method requires us to record compensation expense for all awards granted after the time of adoption and recognize the unvested portion of previously granted awards that remain outstanding at the time of adoption as the requisite service is rendered. The compensation cost is based on the grant-date fair value of the equity award. Stock-based compensation expense recognized during the period is based on the value of the portion of share-based payment awards that is ultimately expected to vest during the period. Stock-based compensation expense recognized in our Condensed Consolidated Statements of Operations for the three months ended March 31, 2006 includes compensation expense for share-based payment awards granted prior to, but not yet vested as of, January 1, 2006 based on the grant date fair value estimated in accordance with the pro forma provisions of SFAS 123 and compensation expense for the share-based payment awards granted subsequent to January 1, 2006 based on the grant date fair value estimated in accordance with the provisions of SFAS 123R. Our implementation of SFAS 123R did not materially affect our results of operations, cash flows or financial condition.

SFAS 156 “Accounting for Servicing of Financial Assets - An Amendment of FASB Statement No. 140” (SFAS 156)

In March 2006, the FASB issued SFAS 156. SFAS 156 requires an entity to recognize a servicing asset or servicing liability each time it undertakes an obligation to service a financial asset by entering into a servicing contract in certain situations and requires all separately recognized servicing assets and servicing liabilities to be initially measured at fair value, if practicable. SFAS 156 also requires separate presentation of servicing assets and servicing liabilities subsequently measured at fair value in the statement of financial position and additional disclosures for all separately recognized servicing assets and servicing liabilities. The requirements for recognition and initial measurement of servicing assets and servicing liabilities should be applied prospectively to all transactions after the effective date of this statement. This statement will be effective on January 1, 2007. Management has not completed the process of determining the effect of this statement on our financial statements.

Future Accounting Changes

The FASB’s standard-setting process is ongoing and until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations and financial position that may result from any such future changes. The FASB is currently working on several projects including accounting for uncertain tax positions, fair value measurements, business combinations, revenue recognition, pension and postretirement benefit plans, liabilities and equity, earnings per share calculations, subsequent events and related tax impacts. We also expect to see more FASB projects as a result of its desire to converge International Accounting Standards with GAAP. The ultimate pronouncements resulting from these and future projects could have an impact on our future results of operations and financial position.

3. RATE MATTERS

As discussed in our 2005 Annual Report, our subsidiaries are involved in rate and regulatory proceedings at the FERC and state commissions. The Rate Matters note within our 2005 Annual Report should be read in conjunction with this report to gain a complete understanding of material rate matters still pending that could impact results of operations and cash flows. Rate proceedings that are not expected to adversely affect future results of operations and cash flows are not included in this report. The following sections discuss current activities and update the 2005 Annual Report.

APCo Virginia Environmental and Reliability Costs

The Virginia Electric Restructuring Act includes a provision that permits recovery, during the extended capped rate period ending December 31, 2010, of incremental environmental compliance and transmission and distribution (T&D) system reliability (E&R) costs prudently incurred after July 1, 2004. In 2005, APCo filed a request with the Virginia SCC and updated it through supplemental testimony seeking recovery of $21 million of incremental E&R costs incurred from July 2004 through September 2005. Through March 31, 2006, APCo deferred $26 million of incurred E&R costs.

In January 2006, the Virginia SCC staff proposed that APCo recover current, rather than past, incremental E&R costs in its electric rates at an ongoing level of $20 million. The staff proposal would effectively disallow the recovery of costs incurred prior to the authorization and implementation of new rates, including all incremental E&R costs that were established as a regulatory asset. We believe the staff’s position is contrary to the statute and an October 2005 Virginia SCC order, which denied APCo’s original request to recover projected costs in favor of the Virginia SCC’s interpretation that the law only permits recovery of actual incurred incremental E&R costs that the commission found prudent.

Hearings concluded in March 2006. At the hearings, the staff amended its testimony to recommend a $24 million increase in APCo’s ongoing rates. If the Virginia SCC reverses its position and adopts the staff’s recommendation or denies recovery of any of APCo’s deferred E&R costs, future results of operations and cash flows could be adversely impacted.

APCo Virginia Base Rate Case

In May 2006, APCo filed a request with the Virginia SCC seeking an increase in base rates of $225 million to recover increasing costs including an equity return. In addition, APCo requested to move off-system sales margins currently credited to customers through base rates to the fuel factor where they can be adjusted annually. This proposed off-system sales rate credit of $27 million partially offsets the $225 million requested increase in base rates for a net increase of $198 million. APCo requested that the new rates be implemented on an interim basis beginning in the June 2006 customer billings. We are unable to predict the ultimate effect of this filing on future revenues, cash flows and financial condition.

APCo and WPCo West Virginia Rate Case

In April 2006, APCo and WPCo reached agreement with the WVPSC staff and intervenors in the West Virginia rate case filed in 2005. The parties filed a settlement agreement with the WVPSC, providing for an initial overall increase in rates of $44 million effective July 28, 2006. The initial annual increase in rates is comprised of :

·	An Expanded Net Energy Cost (ENEC) increase of $56 million for fuel and purchased power expenses;
·	A $23 million special construction surcharge providing recovery of the costs of the Wyoming-Jacksons Ferry 765 kV line and scrubbers to date;
·	A general base rate reduction of $18 million of which $9 million relates to a reduction in depreciation expense which affects cash flows but not earnings; and
·	A $17 million credit for prior over-recoveries of ENEC costs, currently recorded in regulatory liabilities on the Condensed Consolidated Balance Sheets. Therefore, this item impacts cash flows but has no effect on earnings.

In addition, the agreement provides a mechanism that allows APCo and WPCo to adjust their rates annually for the timely recovery of the ongoing investments in scrubbers at APCo’s Mountaineer and John Amos power plants. The estimated future annual increases based on the level of incremental investment in the scrubbers as proposed in the settlement, are projected to result in a $36 million increase in rates effective July 1, 2007, a $14 million increase in rates effective July 1, 2008 and an $18 million increase in rates effective July 1, 2009. The settlement further provides for the reinstatement of ENEC proceedings and its related annual rate adjustment mechanism for changes in fuel and purchased power costs. Although the agreement is comprehensive in all respects, one issue regarding the rates for a special contract industrial customer remains unresolved. The WVPSC ordered legal briefs to be filed by May 4, 2006 with responses to be filed by May 15, 2006. At this time, the WVPSC has not approved the settlement agreement and therefore, management is unable to predict the ultimate effect of this filing on future revenues and cash flows.

I&M Depreciation Study Filing

In December 2005, I&M filed a petition with the IURC, seeking authorization to revise the book depreciation rates applicable to its electric utility plant in service. Based on a depreciation study included in the filing, I&M recommended a decrease in pretax annual depreciation expense of approximately $69 million on an Indiana jurisdictional basis reflecting an NRC-approved 20-year extension of the Cook Nuclear Plant licenses for Units 1 and 2 and an extension of the service life of the Tanners Creek coal-fired generating units. This petition is not a request for a change in customers’ electric service rates. Intervenors filed testimony in March 2006 and I&M filed its rebuttal testimony in April 2006. Hearings are scheduled for May 2006. As proposed by I&M, the book depreciation expense reduction would increase earnings, but would not impact cash flows. If approved by the IURC, I&M will currently adjust its book depreciation expense from the approved effective date forward. Management is unable to predict the outcome of this proceeding.

KPCo Rate Filing

In March 2006, the KPSC approved the settlement agreement in KPCo’s 2005 base rate case. The approved agreement provides for a $41 million annual increase in revenues effective March 30, 2006 and the retention of the existing environmental surcharge tariff. No return on equity is specified by the settlement terms except to note that KPCo will use a 10.5% return on equity to calculate the environmental surcharge tariff and for AFUDC purposes.

PSO Fuel and Purchased Power and its Possible Impact on AEP East companies and AEP West companies

In 2002, PSO under-recovered $44 million of fuel costs resulting from a reallocation among AEP West companies of purchased power costs for periods prior to January 1, 2002. In July 2003, PSO proposed collection of those reallocated costs over 18 months. In August 2003, the OCC staff filed testimony recommending PSO recover $42 million of the reallocation of purchased power costs over three years. The OCC subsequently expanded the case to include a full prudence review of PSO’s 2001 through 2003 fuel and purchased power practices. In January 2006, the OCC staff and intervenors issued supplemental testimony alleging that AEP deviated from the FERC-approved method of allocating off-system sales margins between AEP East companies and AEP West companies and among AEP West companies. The OCC staff proposed that the OCC offset the $42 million of under-recovered fuel with their proposed reallocation of off-system sales margins of $27 million to $37 million. In February 2006, the OCC staff filed a report regarding $9 million of the reallocation assigned to wholesale customers. In that report, the OCC staff concluded that the reallocation assigned to wholesale customers has been refunded, thus removing that issue from their recommendation.

In 2004, an Oklahoma ALJ found that the OCC lacks authority to examine whether PSO deviated from the FERC-approved allocation methodology and held that any such complaints should be addressed at the FERC. The OCC has not ruled on appeals by intervenors of the ALJ’s finding. In September 2005, the United States District Court for the Western District of Texas issued an order in a TNC fuel proceeding, preempting the PUCT from reallocating off-system sales margins between the AEP East companies and AEP West companies. The federal court agreed that the FERC has jurisdiction over that allocation. The PUCT appealed the ruling.

PSO does not agree with the intervenors’ and the OCC staff’s recommendations and proposals and will defend its position vigorously. If the OCC denies recovery of any portion of the $42 million under-recovery of reallocated costs or offsets under-recovered fuel deferrals with additional reallocated off-system sales margins, our future results of operations and cash flows could be adversely affected. However, if the position taken by the federal court in Texas applies to PSO’s case, the OCC could be preempted from disallowing fuel recoveries for alleged improper allocations of off-system sales margins between AEP East companies and AEP West companies. The OCC or another party may file a complaint at the FERC alleging the allocation of off-system sales margins adopted by PSO is improper which could result in an adverse effect on future results of operations and cash flows for AEP and the AEP East companies. To date, there has been no claim asserted at the FERC that AEP deviated from the approved allocation methodologies. Management is unable to predict the ultimate effect of these Oklahoma fuel clause proceedings and future FERC proceedings, if any, on future results of operations, cash flows and financial condition.

SWEPCo Louisiana Fuel Inquiry

In March 2006, the Louisiana Public Service Commission (LPSC) closed its inquiry into SWEPCo’s fuel and purchased power procurement activities during the period January 1, 2005 through October 31, 2005. The LPSC approved the LPSC staff’s report, which concluded that SWEPCo’s activities were appropriate and did not identify any disallowances or areas for improvement.

SWEPCo PUCT Staff Review of Earnings

In October 2005, the staff of the PUCT reported the results of its review of SWEPCo’s year-end 2004 earnings. Based on the staff’s adjustments to the information submitted by SWEPCo, the report indicates that SWEPCo is receiving excess revenues of approximately $15 million. The staff has engaged SWEPCo in discussions to reconcile the earnings calculation and to consider possible ways to address the results. After those discussions, the PUCT staff informed SWEPCo that they will not further pursue the matter.

ERCOT Price-to-Beat (PTB) Fuel Factor Appeal

Several parties including the Office of Public Utility Counsel and cities served by both TCC and TNC appealed the PUCT’s December 2001 orders establishing initial PTB fuel factors for Mutual Energy CPL and Mutual Energy WTU (TCC’s and TNC’s former affiliated REPs, respectively). In June 2003, the District Court ruled the PUCT record lacked substantial evidence regarding the effect of loss of load due to retail competition on the generation requirements of both Mutual Energy WTU and Mutual Energy CPL and on the PTB rates. In an opinion issued on July 28, 2005, the Texas Court of Appeals reversed the District Court. The cities are appealing the appeals court decision to the Texas Supreme Court. Management cannot predict the outcome of further appeals, but a reversal of the favorable court of appeals decision regarding the loss of load issue could result in the issue being returned to the PUCT for further consideration. If the PUCT were to reverse its decision and order refunds of PTB revenues, it could adversely impact results of operations and cash flows.

RTO Formation/Integration Costs

In 2005, the FERC approved the amortization of approximately $18 million of deferred RTO formation/integration costs not billed by PJM over 15 years and $17 million of deferred PJM-billed integration costs over 10 years. The total amortization related to such costs was $1 million in both the first quarter of 2006 and 2005. As of both March 31, 2006 and December 31, 2005, the AEP East companies had $31 million of deferred unamortized RTO formation/integration costs.

In a December 2005 order, the FERC approved the inclusion of a separate rate in the PJM AEP zone OATT to recover the amortization of deferred RTO formation/integration costs not billed by PJM of $2 million per year. The AEP East companies will be responsible for paying the majority of the amortized costs assigned by the FERC to the AEP East zone since their internal load is the bulk (about 85%) of the transmission load in the AEP zone.

In 2005, the FERC denied a request we jointly filed with two other utilities to recover deferred PJM-billed integration costs from all load-serving entities in the PJM RTO zone over a ten-year period. Instead, the FERC ordered the companies to make a compliance filing to recover the PJM-billed integration costs solely from the zones of the requesting companies. Subsequently, the FERC approved the compliance rate, and PJM began charging the rate to load serving entities in the AEP zone (and the other companies’ zones), including the AEP East companies on behalf of the load they serve in the AEP zone (about 85% of the total load in the AEP zone). In June 2005, AEP filed a request for rehearing. In October 2005, the FERC granted our rehearing request and set the following two issues for settlement discussions and, if necessary, for hearing: (i) whether the PJM OATT is unjust and unreasonable without PJM region-wide recovery of PJM-billed integration costs and (ii) a determination of a just and reasonable carrying charge rate on the deferred PJM-billed integration costs. In April 2006, a settlement was filed with the FERC that allows recovery of our deferred PJM-billed integration costs from the PJM region over ten years. In addition, the settlement reduced the return on equity component included in our carrying charge rate to 10.5%, which will have an immaterial impact on future results of operations.

We recover the amortization of RTO formation/integration costs billed to our AEP East companies in Ohio for CSPCo and OPCo, and in Kentucky for KPCo. We have not commenced recovery in West Virginia (where APCo filed a settlement agreement in its base rate case with the WVPSC that included the recovery of its amortization of these costs), Virginia (where APCo filed a base rate case which includes recovery of these costs) or Indiana (where I&M is subject to a rate cap until June 30, 2007).

Until APCo and I&M can adjust their retail rates to recover the amortization of both RTO-related deferred costs, results of operations and cash flows will be adversely affected by the amortizations. If the Virginia, West Virginia or Indiana commissions disallow recovery of any portion of the billed amortization of deferred RTO formation/integration costs or no appeal is ultimately successful, it would have an adverse impact on future results of operations and cash flows.

Transmission Rate Proceedings at the FERC

SECA Revenue

In accordance with FERC orders, we collected SECA rates to mitigate lost through-and-out transmission service (T&O) revenues through March 31, 2006, when SECA rates expired. The FERC set SECA rate issues for hearing and indicated that the SECA rate revenues are subject to refund or surcharge. The AEP East companies recognized net SECA revenues of $35 million and $26 million during the first quarter of 2006 and 2005, respectively. Since the implementation of SECA rates in December 2004 through March 2006, we have recognized net SECA revenues of $174 million. Intervenors in the SECA proceeding are objecting to the SECA rates and our method of determining those rates. The SECA hearings are scheduled to begin in early May 2006. At this time, management is unable to determine the outcome of the FERC’s SECA rate proceeding and if it will impact future results of operations and cash flows.

AEP East Transmission Revenue Requirement and Rates

In December 2005, the FERC approved an uncontested settlement allowing increases to our wholesale transmission rates in three steps: first, beginning November 1, 2005, second, beginning April 1, 2006 when the SECA revenues were eliminated and third, on the later of August 1, 2006 or the first day of the month following the date when our Wyoming-Jacksons Ferry transmission line enters service, currently expected in June 2006.

PJM Regional Transmission Rate Proceeding

In a separate proceeding, at our urging, the FERC instituted an investigation of PJM’s zonal rate regime, indicating that the present rate regime may need to be replaced through establishment of regional rates that would compensate AEP, among others, for the regional transmission service provided with their owned extra-high-voltage facilities that benefit customers throughout PJM. In September 2005, AEP and a nonaffiliated utility (Allegheny Power or AP) jointly filed a regional transmission rate design proposal with the FERC.

This filing proposes and supports a new PJM rate regime generally referred to as Highway/Byway. Under our proposed Highway/Byway rate design, the cost of all transmission facilities in the PJM region operated at a voltage of 345 kV or higher would be included in a “Highway” rate that all load serving entities (LSEs) would pay based on peak demand. The cost of transmission facilities operating at lower voltages would be collected in the zones where those costs are presently charged under PJM’s rate design. In a competing Highway/Byway proposal, a group of LSEs proposed rates that would include 500 kV and higher existing facilities and some facilities at lower voltages in the Highway rate. Another proposal uses facilities 200 kV or higher in the Highway rate. These alternative Highway/Byway proposals are being challenged by a majority of transmission owners in the PJM region who favor continuation of the PJM rate design. In January 2006, the FERC staff issued testimony and exhibits supporting a PJM-wide flat rate or “Postage Stamp” type of rate design. Hearings were held in April 2006.

The AEP/AP Highway/Byway design would result in incremental net revenues of approximately $125 million per year for the transmission-owning AEP East companies. The competing Highway/Byway proposals filed by others would also produce incremental net revenues to the AEP East transmission-owning companies, but at a much lower level. The staff rate design would produce slightly more net revenue for AEP than the original AEP/AP proposal. We cannot at this time estimate the outcome of the proceeding; however, adoption of any of the new proposals would have a positive effect on our revenues and results of operations, compared to the continuation of the PJM rates that went into effect on April 1, 2006 when the SECA rates expired.

As of March 31, 2006, SECA transition rates did not fully compensate the AEP East companies for their lost T&O revenues. Effective with the expiration of the SECA transition rates on March 31, 2006, the increase in the AEP East zonal transmission rates applicable to AEP’s internal load and wholesale transmission customers in AEP’s zone was not sufficient to replace the SECA transition rate revenues; however, a favorable outcome in the PJM regional transmission rate proceeding, made retroactive to April 1, 2006 could mitigate a large portion of the expected shortfall. Full mitigation of the effects of eliminated T&O revenues and the less favorable terminated SECA revenues will require cost recovery through retail rate proceedings. The status of the retail rate proceedings are as follows:

·	In Kentucky, KPCo settled a rate case, which provides for the recovery of the transmission revenue shortfall.
·	APCo filed a settlement agreement in West Virginia, which included recovery of the lost T&O/SECA transmission revenues.
·	A pending rate request filed in February 2006 in Ohio addresses the significant reduction in FERC transmission revenues.
·	In Virginia, APCo filed a request for revised rates, which includes recovery of the lost T&O/SECA transmission revenues.
·	In Indiana, I&M is precluded by a rate cap from raising its rates until July 1, 2007.

Management is unable to predict whether the FERC will approve a regional rate to mitigate the loss of T&O/SECA revenues, or if not, when, and if, the effect of the loss of T&O/SECA transmission revenues will be recoverable on a timely basis in all of the AEP East state retail jurisdictions and from wholesale LSEs within the PJM region.

Future results of operations, cash flows and financial condition would be adversely affected if the approved FERC transmission rates are not sufficient to replace the lost T&O/SECA revenues and the resultant increase in the AEP East companies’ unrecovered transmission costs are not fully recovered in retail rates, or the FERC’s review of our previously collected SECA rates results in a refund to customers.

Allocation Agreement between AEP East companies and AEP West companies

The SIA provides, among other things, for the methodology of sharing trading and marketing margins between the AEP East companies and AEP West companies. In March 2006, the FERC approved our proposed methodology to be used effective April 1, 2006 and beyond. The approved allocation methodology is based upon the location of the specific trading and marketing activity, with margins resulting from trading and marketing activities originating in PJM and MISO generally accruing to the benefit of the AEP East companies and trading and marketing activities originating in SPP and ERCOT generally accruing to the benefit of PSO and SWEPCo. Previously, the SIA allocation provided for a different method of sharing all such margins between both AEP East companies and AEP West companies. The impact on future results of operations and cash flows will depend upon the level of future margins by region and the status of cost recovery mechanisms by state; however, in general, it is expected to have a favorable effect on future results of operations and cash flows. Our total trading and marketing margins are unaffected by the allocation methodology.

4. CUSTOMER CHOICE AND INDUSTRY RESTRUCTURING

We are affected by customer choice initiatives and industry restructuring. The Customer Choice and Industry Restructuring note in our 2005 Annual Report should be read in conjunction with this report to gain a complete understanding of material customer choice and industry restructuring matters without significant changes since year-end. The following paragraphs discuss significant current events related to customer choice and industry restructuring and update the 2005 Annual Report.

TEXAS RESTRUCTURING

The PUCT issued an order in TCC’s True-up Proceeding in February 2006, which determined that TCC’s true-up regulatory asset was $1.475 billion, which included carrying costs through September 2005. An order on rehearing was issued by the PUCT in April 2006, which made minor changes to, but otherwise affirmed, the February 2006 order. We expect to appeal, seeking additional recovery consistent with the Texas Restructuring Legislation and related rules. Other parties may appeal the PUCT’s order claiming it permits TCC to over-recover its stranded costs.

TCC Securitization Proceeding

TCC filed an application in March 2006 requesting to securitize $1.8 billion of net stranded generation plant costs and related carrying costs to September 1, 2006. The $1.8 billion does not include TCC’s other true-up items, which are partially offsetting in nature. These obligations total $491 million and would be payable through a CTC over a period determined by the PUCT. See “CTC Proceeding for Other True-up Items” section of this note. Intervenors and the PUCT staff filed testimony in April 2006. Hearings are scheduled for May. It is possible that the PUCT could reduce the securitization amount by all or some portion of the negative other true-up items. If that occurs, a negative impact on the timing of cash flows could result. Cash flows from securitization would be adversely impacted if the PUCT reduces TCC’s computation of the amount to be securitized.

In addition, the intervenors raised three issues totaling $138 million which were addressed by the PUCT in prior proceedings - the appropriate interest rate for both stranded cost and deferred fuel and the treatment of excess earnings refunds. Other issues raised by the intervenors dealt with the amounts to be securitized versus refunded to customers through the CTC, customer class allocation issues and debt defeasance strategies.

The difference between the recorded securitizable true-up regulatory asset of $1.5 billion at March 31, 2006 and our securitization request of $1.8 billion is detailed in the table below:

	(in millions)
Stranded Generation Plant Costs	$	969
Net Generation-related Regulatory Asset		249
Excess Earnings		(49	)
Recorded Net Stranded Generation Plant Costs		1,169
Recorded Debt Carrying Costs on Recorded Net Stranded Generation Plant Costs		284
Recorded Securitizable True-up Regulatory Asset		1,453
Unrecorded But Recoverable Equity Carrying Costs		212
Unrecorded Estimated April 2006 - August 2006 Debt Carrying Costs		40
Unrecorded Securitization Issuance Costs		24
Unrecorded Excess Earnings, Related Return and Other		75
Securitization Request	$	1,804

Deferred Investment Tax Credits and Excess Deferred Federal Income Taxes

In TCC’s true-up order, the PUCT reduced net stranded generation plant costs by $51 million related to the present value of accumulated deferred investment tax credits (ADITC) and by $10 million related to excess deferred federal income taxes (EDFIT) associated with TCC’s generating assets. TCC testified that the sharing of these tax benefits with customers may be a violation of the Internal Revenue Code’s normalization provisions. The federal tax statutes require public utilities to "normalize" or sychronize the tax benefits derived from ADITC and EDFIT with the financial and regulatory life of the regulated plant assets that give rise to the benefit. The normalization rules prohibit returning the benefits to ratepayers faster than the underlying assets are recovered for rate purposes. Once these assets are no longer regulated, the normalization provisions do not permit these benefits to be returned to ratepayers. In the true-up order, the PUCT agreed to consider revisiting this issue if the IRS ruled that the flow-through of ADITC and EDFIT constituted a normalization violation. Tax counsel advised management that a normalization violation should not occur until all remedies under law have been exhausted and the tax benefits are returned to ratepayers under a final, nonappealable rate order. Although ADITC and EDFIT are recorded as a liability on TCC’s books, such amounts are not reflected as a reduction of TCC’s recorded securitizable true-up regulatory asset in the above reconciliation.

TCC filed a request for a private letter ruling from the IRS in June 2005 to determine whether the PUCT’s action would result in a normalization violation. On April 21, 2006 the IRS informed TCC that they are ruling against the PUCT treatment and consider the flowthrough of ADITC and EDFIT a normalization violation.

In a motion for rehearing, TCC asked the PUCT to reconsider its treatment of ADITC and EDFIT in light of the position of the IRS. In its order on rehearing, the PUCT declined to change its treatment. The PUCT withdrew the language stating it would revisit the issue if their treatment was ruled a normalization violation by the IRS and replaced it with an additional explanation of the basis for its original decision. In a motion for a second rehearing filed April 24, 2006, TCC informed the PUCT that the IRS intended to rule adversely on the private letter ruling request.

If a normalization violation occurs, it could result in the repayment of TCC’s ADITC on all property, including transmission and distribution, which approximates $105 million as of March 31, 2006 and also a loss of the accelerated tax depreciation election in the future. Management intends to continue working with the PUCT to avoid a normalization violation that would adversely affect future results of operations and cash flows.

CTC Proceeding for Other True-up Items

TCC incurs carrying costs on the net negative other true-up regulatory liability balances until fully refunded. The principal components of the CTC rate reduction are an over-recovered fuel balance, the retail clawback and the ADFIT benefit related to TCC’s stranded generation cost, offset by a positive wholesale capacity auction true-up regulatory asset balance. TCC anticipates filing to implement a negative CTC (as a rate reduction) for its net other true-up items in the second quarter of 2006.

The difference between the components of TCC’s recorded net regulatory liabilities - other true-up items as of March 31, 2006 and its planned CTC proceeding request are detailed below:

	(in millions)
Wholesale Capacity Auction True-up	$	61
Carrying Costs on Wholesale Capacity Auction True-up		17
Retail Clawback		(61	)
Deferred Over-recovered Fuel Balance		(177	)
Recorded Net Regulatory Liabilities - Other True-up Items		(160	)
ADFIT Benefit		(328	)
Unrecorded Carrying Costs and Other		(3	)
Estimated CTC Request	$	(491	)

Fuel Balance Recoveries

In September 2005, the Federal District Court, Western District of Texas, issued an order precluding the PUCT from enforcing its ruling in the TNC fuel proceeding regarding the PUCT’s reallocation of off-system sales margins. TCC has a similar appeal outstanding and believes that the same ruling should result. The impact of the favorable Federal District court order, if upheld on appeal, could result in reductions to the over-recovered fuel balances of $8 million for TNC and $14 million for TCC. The PUCT appealed the Federal Court decision to the United States Court of Appeals for the Fifth Circuit. If the PUCT is unsuccessful in the federal court system, it may file a complaint at the FERC to address the allocation issue. We are unable to predict if the Federal District Court’s decision will be upheld or whether the PUCT will file a complaint at the FERC. Pending further clarification, TCC and TNC have not reversed their related provisions for fuel over-recovery. If the PUCT or another party were to file a complaint at the FERC and is successful, it could result in an adverse effect on results of operations and cash flows for the AEP East companies. An unfavorable FERC ruling may result in a reallocation of off-system sales margins from AEP East companies to AEP West companies. If the adjustments were applied retroactively, the AEP East companies may be unable to recover the amounts from their customers due to past frozen rates, past inactive fuel clauses and fuel clauses that do not include off-system sales credits.

Carrying Costs on Net True-up Regulatory Assets Impacting Securitization and CTC Proceedings

In TCC’s True-up Proceeding, the PUCT allowed TCC to recover carrying costs at an 11.79% overall pretax weighted average cost of capital rate from its unbundled cost of service rate proceeding. The recorded embedded debt component of the carrying cost rate is 8.12%. Through March 2006, TCC recorded $301 million of debt-related carrying costs ($284 million on stranded generation plant costs impacting the securitization proceeding and $17 million on wholesale capacity auction true-up impacting the CTC proceeding). The remaining equity component of $166 million will be recognized in income as collected. TCC will continue to accrue a debt-related carrying cost until its net true-up regulatory asset is fully recovered. Equity carrying costs are recognized in income as collected.

In January 2006, the PUCT approved publication of a proposed rule that would reduce the 11.79% overall carrying cost rate on nonsecuritized true-up amounts to the most recently approved weighted average cost of debt, which would be 5.70% for TCC. The effective date of the change is proposed to be (i) January 1, 2002 for utilities that have not received a final true-up order or (ii) the date the rule is adopted for utilities that have received a final order. There will be a 45-day comment period from the date of adoption. TCC received an order in the True-up Proceeding in February 2006 and an order on rehearing in April 2006 (which is subject to rehearing). TCC asserted in comments filed in the rulemaking proceeding that the rule change should not have retroactive application. However, TCC cannot predict if the rule will be adopted, or if it will be adopted in its present prospective form for utilities that have received their final true-up order. If adopted retroactively, it would have an adverse effect on future results of operations and cash flows.

Summary

Our recorded securitizable true-up regulatory asset at March 31, 2006 of $1.5 billion, net of regulatory liabilities - other true-up items of $160 million, accurately reflects the PUCT’s order in TCC’s True-up Proceeding. TCC performed a probability of recovery impairment test on its net true-up regulatory asset taking into account the treatment ordered by the PUCT and determined that the projected cash flows from the net transition charges would be more than sufficient to recover TCC’s recorded net true-up regulatory asset. As a result, we have not recorded any additional impairment. Barring any future disallowances to TCC’s net recoverable true-up regulatory asset in its true-up or subsequent proceedings, TCC expects to amortize its total net true-up regulatory asset commensurate with recovery over periods established by the PUCT in future securitization and CTC proceedings. If we determine in future securitization and CTC proceedings that it is probable TCC cannot recover a portion of its recorded net true-up regulatory asset and we are able to estimate the amount of such nonrecovery, we would record a provision for such amount which could have an adverse effect on future results of operations, cash flows and possibly financial condition. TCC intends to pursue rehearing and appeals to vigorously seek relief as necessary in both federal and state court where it believes the PUCT’s rulings are contrary to the Texas Restructuring Legislation, PUCT rulemakings and federal law. It is expected that municipal customers and other intervenors will also pursue vigorously court appeals to further reduce TCC’s true-up recoveries. Although TCC believes it has meritorious arguments, management cannot predict the ultimate outcome of any future proceedings, requested rehearings or court appeals. If municipal customers and other intervenors succeed in their expected appeals, it could have a material adverse effect on future results of operations, cash flows and financial condition.

Texas Restructuring - SPP

In April 2006, the PUCT proposed a possible delay in customer choice in the SPP area of Texas until no sooner than January 1, 2011. SWEPCo and a small portion of TNC’s business operate in SPP.

OHIO RESTRUCTURING

Rate Stabilization Plans

In January 2005, the PUCO approved Rate Stabilization Plans (RSPs) for CSPCo and OPCo (the Ohio companies). The approved plans in each of 2006, 2007 and 2008 provide, among other things, for CSPCo and OPCo to raise their generation rates by 3% and 7%, respectively, and provide for possible additional annual generation rate increases of up to an average of 4% per year based on supporting the request for additional revenues for specified costs. CSPCo’s potential for the additional annual 4% generation rate increases is diminished by approximately three-quarters in 2006 and to a lesser extent in 2007 and 2008 due to the power acquisition rider approved by the PUCO in the Monongahela Power service territory acquisition proceeding and the recovery of pre-construction costs for the IGCC Plant (see “IGCC Plant” section of this note below). OPCo’s potential for the additional annual 4% generation rate increases is diminished in 2006 by approximately one-quarter and to a lesser extent in 2007 due to the recovery of pre-construction costs for the IGCC plant. The RSPs also provide that the Ohio companies can recover in 2006, 2007 and 2008 estimated 2004 and 2005 environmental carrying costs and PJM-related administrative costs and congestion costs net of financial transmission rights (FTR) revenue related to their obligation as the Provider of Last Resort (POLR) in Ohio’s customer choice program. Pretax earnings increased by $8 million for CSPCo and $20 million for OPCo in the first quarter of 2006 from all the RSP recoveries less the amortization of RSP deferrals net of the recognition of equity carrying charges from 2004 and 2005.

In the second quarter of 2005, the Ohio Consumers’ Counsel filed an appeal to the Ohio Supreme Court that challenged the RSPs and also argued that there was no POLR obligation in Ohio and, therefore, CSPCo and OPCo are not entitled to recover POLR charges. In Dayton Power and Light Company's proceeding, the Ohio Supreme Court concluded that there is a POLR obligation in Ohio, supporting the Ohio companies' position that they can recover a POLR charge. In another Ohio Supreme Court decision involving FirstEnergy Corporation's Ohio electric companies, the Court held that the PUCO-approved RSPs for Ohio electric companies did not comply with the statutory provision regarding the availability of a competitive bid alternative for customers. The Ohio companies believe their RSPs are factually different from FirstEnergy Corporation's Ohio electric companies' RSPs and comply with the applicable statute. However, if the Ohio Supreme Court reverses the PUCO’s authorization of the POLR charge, CSPCo and OPCo’s future earnings will be adversely affected. In addition, if the RSP order were determined on appeal to be illegal in its entirety under the Ohio Electric Restructuring Act of 1999, it would have an initial adverse effect on results of operations, cash flows and possibly financial condition. Although we believe that the RSP plan is legal and we intend to defend vigorously the PUCO’s order, we cannot predict the ultimate outcome of the pending litigation.

IGCC Plant

In March 2005, the Ohio companies filed a joint application with the PUCO seeking authority to recover costs related to building and operating a new 600 MW IGCC power plant using clean-coal technology. The application proposed cost recovery associated with the IGCC plant in three phases: Phase 1, recovery of $24 million in pre-construction costs during 2006; Phase 2, recovery of construction-financing costs; and Phase 3, recovery, or refund, in distribution rates of any difference between the market-based standard service offer price for generation and the cost of operating and maintaining the plant, including a return on and return of the projected $1.2 billion cost of the plant along with fuel, consumables and replacement power. The proposed recoveries in Phases 1 and 2 would be applied against the 4% limit on additional generation rate increases the Ohio companies could request in 2006, 2007 and 2008 under their RSPs. As of March 31, 2006, the Ohio companies deferred $10 million of pre-construction IGCC costs.

On April 10, 2006, the PUCO issued an order finding that the PUCO has the jurisdiction to approve the proposed cost recovery and authorizing the Ohio companies to implement Phase 1 of the cost recovery proposal. The Ohio companies filed a tariff to recover Phase 1 pre-construction costs over a twelve-month period. The PUCO deferred ruling on Phases 2 and 3 cost recovery until further hearings are held. No date for a further hearing has been set.

Transmission Rate Filing

In February 2006, the Ohio companies filed a request with the PUCO for a two-step increase in their transmission rates. In the filing, the first increase would be effective April 1, 2006 to reflect their share of the loss of SECA revenues and the second increase would be effective the later of August 2006 or the first day of the month following the date when AEP’s Wyoming-Jacksons Ferry transmission line enters service, currently expected to occur on June 30, 2006. We anticipate, if approved, the filing will result in increased revenues for CSPCo and OPCo of $32 million and $42 million, respectively, in 2006 and increasing in 2007 to $46 million and $59 million for CSPCo and OPCo, respectively. This filing intends to recover the new OATT rates resulting from the settlement of our March 2005 filing with the FERC requesting increased OATT rates in a three-step increase. In March 2006, the PUCO suspended the effective date of the new rates to provide its staff additional time to conduct its review of the application. In their application, the Ohio companies requested permission to defer for future recovery their unrecovered transmission costs as a result of the loss of SECA revenues starting April 1, 2006 if the PUCO did not issue an order in this case in time to implement the increase on April 1, 2006. If the PUCO does not approve the future recovery of the unrecovered transmission costs effective April 1, 2006 when the SECA revenues ceased, results of operations and cash flows will be adversely affected.

Storm Cost Recovery Filing

In March 2006, the Ohio companies filed an application with the PUCO to implement tariff riders to recover a portion of previously-expensed costs of restoring service disrupted by severe winter storms in December 2004 and January 2005. CSPCo and OPCo each requested recovery of approximately $12 million of such costs.

PUCO Staff Report on Service Reliability

In December 2003, the Ohio companies entered into a stipulation agreement regarding distribution service reliability. The stipulation agreement covered the years 2004 and 2005 and, among other features, established certain distribution service reliability measures that the Ohio companies were to meet. In April 2006, the staff of the PUCO submitted a commission-ordered investigative report on the Ohio companies’ compliance with the stipulation agreement. In the report, the staff asserted that the Ohio companies failed to fulfill all the terms of the stipulation agreement. The staff recommended various consequences for the PUCO’s consideration, including the potential for civil forfeitures, monthly payments until the terms of the stipulation agreement have been met and providing credits to customers. The staff also suggested that the PUCO could explore possible improvements in the Ohio companies’ management of the reliability process. Finally, the staff recommended that the Ohio companies file, in a companion docket, a comprehensive plan to improve their system reliability. The PUCO ordered the Ohio companies to respond to the staff's recommendations concerning consequences by May 23, 2006, after which the PUCO will determine how to proceed. In the companion docket, the PUCO directed the Ohio companies to prepare a plan to enhance service reliability. A timeline for submission of that plan has not been set. The PUCO indicated that it will set a procedural schedule in the future. Although we believe that the Ohio companies have substantially met the terms and expectations of the stipulation agreement, we cannot predict the outcome of these proceedings. If the PUCO adopts the staff’s recommendations, results of operations and cash flows could be adversely affected.

Customer Choice Deferrals

As provided in stipulation agreements approved by the PUCO in 2000, we defer customer choice implementation costs and related carrying costs in excess of $40 million. The agreements provide for the deferral of these costs as regulatory assets until the next distribution base rate cases. Through March 31, 2006, we incurred $101 million of such costs and, accordingly, we deferred $53 million of such costs for probable future recovery in distribution rates. We have not recorded $8 million of equity carrying costs, which are not recognized until collected. Recovery of these regulatory assets is subject to PUCO review in future Ohio filings for new distribution rates. Pursuant to the RSPs, recovery of these amounts is deferred until the next distribution rate filing to change rates after December 31, 2008. We believe that the deferred customer choice implementation costs were prudently incurred to implement customer choice in Ohio and should be recoverable in future distribution rates. If the PUCO determines that any of the deferred costs are unrecoverable, it would have an adverse impact on future results of operations and cash flows.

5. COMMITMENTS AND CONTINGENCIES

As discussed in the Commitments and Contingencies note within our 2005 Annual Report, we continue to be involved in various legal matters. The 2005 Annual Report should be read in conjunction with this report in order to understand the other material nuclear and operational matters without significant changes since our disclosure in the 2005 Annual Report. See disclosure below for significant matters and changes in status subsequent to the disclosure made in our 2005 Annual Report.

ENVIRONMENTAL

Federal EPA Complaint and Notice of Violation

The Federal EPA and a number of states have alleged that APCo, CSPCo, I&M, OPCo and other nonaffiliated utilities, including the Tennessee Valley Authority, Alabama Power Company, Cincinnati Gas and Electric Company, Ohio Edison Company, Southern Indiana Gas & Electric Company, Illinois Power Company, Tampa Electric Company, Virginia Electric Power Company and Duke Energy, modified certain units at coal-fired generating plants in violation of the NSR requirements of the CAA. The Federal EPA filed its complaints against our subsidiaries in U.S. District Court for the Southern District of Ohio. The court also consolidated a separate lawsuit, initiated by certain special interest groups, with the Federal EPA case. The alleged modifications occurred at our generating units over a 20-year period. A bench trial on the liability issues was held during July 2005. Briefing has concluded but no decision has been issued. A bench trial on remedy issues is scheduled for January 2007.

Under the CAA, if a plant undertakes a major modification that directly results in an emissions increase, permitting requirements might be triggered and the plant may be required to install additional pollution control technology. This requirement does not apply to activities such as routine maintenance, replacement of degraded equipment or failed components or other repairs needed for the reliable, safe and efficient operation of the plant. The CAA authorizes civil penalties of up to $27,500 ($32,500 after March 15, 2004) per day per violation at each generating unit. In 2001, the District Court ruled claims for civil penalties based on activities that occurred more than five years before the filing date of the complaints cannot be imposed. There is no time limit on claims for injunctive relief.

The Federal EPA and eight northeastern states each filed an additional complaint containing additional allegations against the Amos and Conesville plants. APCo and CSPCo filed an answer to the northeastern states’ complaint and the Federal EPA’s complaint, denying the allegations and stating their defenses. Cases are also pending that could affect CSPCo’s share of jointly-owned units at Beckjord, Zimmer and Stuart stations. Similar cases have been filed against other nonaffiliated utilities, including Allegheny Energy, Eastern Kentucky Electric Cooperative, Public Service Enterprise Group, Santee Cooper, Wisconsin Electric Power Company, Mirant, NRG Energy and Niagara Mohawk.

Courts have reached different conclusions regarding whether the activities at issue in these cases are routine maintenance, repair, or replacement, and therefore are excluded from NSR. Similarly, courts have reached different results regarding whether the activities at issue increased emissions from the power plants. Appeals on these and other issues have been filed in certain appellate courts, including a petition to appeal to the U.S. Supreme Court in one case. The Federal EPA issued a final rule that would exclude activities similar to those challenged in these cases from NSR as “routine replacements.” In March 2006, the Court of Appeals for the District of Columbia Circuit issued a decision vacating the rule and the Federal EPA filed a petition for rehearing in that case. The Federal EPA also recently proposed a rule that would define “emissions increases” in a way that most of the challenged activities would be excluded from NSR.

We are unable to estimate the loss or range of loss related to any contingent liability we might have for civil penalties under the CAA proceedings. We are also unable to predict the timing of resolution of these matters due to the number of alleged violations and the significant number of issues yet to be determined by the Court. If we do not prevail, we believe we can recover any capital and operating costs of additional pollution control equipment that may be required through regulated rates and market prices of electricity. If we are unable to recover such costs or if material penalties are imposed, it would adversely affect future results of operations, cash flows and possibly financial condition.

SWEPCo Notice of Enforcement and Notice of Citizen Suit

In July 2004, two special interest groups issued a notice of intent to commence a citizen suit under the CAA for alleged violations of various permit conditions in permits issued to several SWEPCo generating plants. In March 2005, the special interest groups filed a complaint in Federal District Court for the Eastern District of Texas alleging violations of the CAA at Welsh Plant. SWEPCo filed a response to the complaint in May 2005.

In July 2004, the Texas Commission on Environmental Quality (TCEQ) issued a Notice of Enforcement to SWEPCo relating to the Welsh Plant containing a summary of findings resulting from a compliance investigation at the plant. In April 2005, TCEQ issued an Executive Director’s Preliminary Report and Petition recommending the entry of an enforcement order to undertake certain corrective actions and assessing an administrative penalty of approximately $228 thousand against SWEPCo based on alleged violations of certain representations regarding heat input in SWEPCo’s permit application and the violations of certain recordkeeping and reporting requirements. SWEPCo responded to the preliminary report and petition in May 2005. The enforcement order contains a recommendation that would limit the heat input on each Welsh unit to the referenced heat input contained within the permit application within 10 days of the issuance of a final TCEQ order and until a permit amendment is issued. SWEPCo had previously requested a permit alteration to remove the reference to a specific heat input value for each Welsh unit.

Management is unable to predict the timing of any future action by TCEQ or the special interest groups or the effect of such actions on results of operations, financial condition or cash flows.

Carbon Dioxide Public Nuisance Claims

In July 2004, attorneys general from eight states and the corporation counsel for the City of New York filed an action in federal district court for the Southern District of New York against AEP, AEPSC, Cinergy Corp, Xcel Energy, Southern Company and Tennesse Valley Authority. That same day, the Natural Resources Defense Council, on behalf of three special interest groups, filed a similar complaint in the same court against the same defendants. The actions alleged that CO₂ emissions from the defendants’ power plants constitute a public nuisance under federal common law due to impacts associated with global warming, and sought injunctive relief in the form of specific emission reduction commitments from the defendants. In September 2004, the defendants, including AEP and AEPSC, filed a motion to dismiss the lawsuits. In September 2005, the lawsuits were dismissed. The trial court’s dismissal was appealed to the Second Circuit Court of Appeals. Briefing has been completed and the case is scheduled to be argued this summer. We believe the actions are without merit and intend to defend vigorously against the claims.

Ontario Litigation

In June 2005, we and nineteen nonaffiliated utilities were named as defendants in a lawsuit filed in the Superior Court of Justice in Ontario, Canada. We have not been served with the lawsuit. The time limit for serving the defendants expired but the case has not been dismissed. The defendants are alleged to own or operate coal-fired electric generating stations in various states that, through negligence in design, management, maintenance and operation, have emitted NO_X,SO₂and particulate matter that have harmed the residents of Ontario. The lawsuit seeks class action designation and damages of approximately $49 billion, with continuing damages of $4 billion annually. The lawsuit also seeks $1 billion in punitive damages. We believe we have meritorious defenses to this action and intend to defend vigorously against it.

OPERATIONAL

Power Generation Facility and TEM Litigation

We have agreements with Juniper Capital L.P. (Juniper) under which Juniper constructed and financed a nonregulated merchant power generation facility (Facility) near Plaquemine, Louisiana and leased the Facility to us. We subleased the Facility to the Dow Chemical Company (Dow). The Facility is a Dow-operated “qualifying cogeneration facility” for purposes of PURPA.

Juniper is a nonaffiliated limited partnership, formed to construct or otherwise acquire real and personal property for lease to third parties, to manage financial assets and to undertake other activities related to asset financing. Juniper arranged to finance the Facility. The Facility is collateral for Juniper’s debt financing. Due to the treatment of the Facility as a financing of an owned asset, we recognized all of Juniper’s funded obligations as a liability. Upon expiration of the lease, our actual cash obligation could range from $0 to $415 million based on the fair value of the assets at that time. However, if we default under the Juniper lease, our maximum cash payment could be as much as $525 million. Because we now report Juniper’s funded obligations totaling $525 million related to the Facility on our Condensed Consolidated Balance Sheets, the fair value of the liability for our guarantee (the $415 million payment discussed above) is not separately reported.

Dow uses a portion of the energy produced by the Facility and sells the excess energy. OPCo agreed to purchase up to approximately 800 MW of such excess energy from Dow for a 20-year term. Because the Facility is a major steam supply for Dow, Dow is expected to operate the Facility at certain minimum levels, and OPCo is obligated to purchase the energy generated at those minimum operating levels (expected to be approximately 220 MW through May 31, 2006 and 270 MW thereafter). OPCo sells the purchased energy at market prices in the Entergy sub-region of the Southeastern Electric Reliability Council market.

OPCo agreed to sell up to approximately 800 MW of energy to Tractebel Energy Marketing, Inc. (TEM) (now known as SUEZ Energy Marketing NA, Inc.) for a period of 20 years under a Power Purchase and Sale Agreement dated November 15, 2000 (PPA), at a price that is currently in excess of market. Beginning May 1, 2003, OPCo tendered replacement capacity, energy and ancillary services to TEM pursuant to the PPA that TEM rejected as nonconforming. Commercial operation for purposes of the PPA began April 2, 2004.

In September 2003, TEM and AEP separately filed declaratory judgment actions in the United States District Court for the Southern District of New York. We alleged that TEM breached the PPA, and we sought a determination of our rights under the PPA. TEM alleged that the PPA never became enforceable, or alternatively, that the PPA was terminated as the result of AEP’s breaches. The corporate parent of TEM (SUEZ-TRACTEBEL S.A.) provided a limited guaranty.

In April 2004, OPCo gave notice to TEM that OPCo (i) was suspending performance of its obligations under the PPA; (ii) would seek a declaration from the District Court that the PPA was terminated; and (iii) would pursue against TEM and SUEZ-TRACTEBEL S.A. under the guaranty, seeking damages and the full termination payment value of the PPA.

A bench trial was conducted in March and April 2005. In August 2005, a federal judge ruled that TEM breached the contract and awarded us damages of $123 million plus prejudgment interest. In August 2005, both parties filed motions with the trial court seeking reconsideration of the judgment. We asked the court to modify the judgment to (i) award a termination payment to us under the terms of the PPA; (ii) grant our attorneys’ fees; and (iii) render judgment against SUEZ-TRACTEBEL S.A. on the guaranty. TEM sought reduction of the damages awarded by the court for replacement electric power products made available by OPCo under the PPA. In January 2006, the trial judge granted our motion for reconsideration concerning TEM’s parent guaranty and increased our judgment against TEM to $173 million plus prejudgment interest, and denied the remaining motions for reconsideration. In March 2006, the trial judge amended the January 2006 order eliminating the additional $50 million damage award.

In September 2005, TEM posted a letter of credit for $142 million as security pending appeal of the judgment. Both parties have filed Notices of Appeal with the United States Court of Appeals for the Second Circuit. If the PPA is deemed terminated or found unenforceable by the court ultimately deciding the case, we could be adversely affected to the extent we are unable to find other purchasers of the power with similar contractual terms and to the extent we do not fully recover the claimed termination value damages from TEM.

Enron Bankruptcy

In connection with our 2001 acquisition of HPL, we entered into an agreement with BAM Lease Company, which granted HPL the exclusive right to use approximately 65 billion cubic feet (BCF) of cushion gas required for the normal operation of the Bammel gas storage facility. At the time of our acquisition of HPL, Bank of America (BOA) and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of our acquisition, Enron and the BOA Syndicate released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.

After the Enron bankruptcy the BOA Syndicate informed HPL of a purported default by Enron under the terms of the financing arrangement. In July 2002, the BOA Syndicate filed a lawsuit against HPL in Texas state court seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. The state court of appeals scheduled oral argument on the appeal for June 2006. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. HPL intends to defend vigorously against BOA’s claims.

In October 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPL, that BOA directly benefited from the sale of HPL and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel reservoir and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas. BOA objected to the Magistrate Judge’s decision. In April 2005, the Judge entered an order overruling BOA’s objections, denying BOA’s Motion to Dismiss and severing and transferring the declaratory judgment claims to the Southern District of New York.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right-to-use agreement and other incidental agreements. We objected to Enron’s attempted rejection of these agreements and filed an adversary proceeding contesting Enron’s right to reject these agreements.

In 2005, we sold our interest in HPL. We indemnified the buyer of HPL against any damages resulting from the BOA litigation up to the purchase price. The determination of the gain on sale and the recognition of the gain is dependent on the ultimate resolution of the BOA dispute and the costs, if any, associated with the resolution of this matter (see Note 8).

Although management is unable to predict the outcome of the remaining lawsuits, it is possible that their resolution could have an adverse impact on our results of operations, cash flows and financial condition.

Shareholder Lawsuits

In the fourth quarter of 2002 and the first quarter of 2003, three putative class action lawsuits were filed against AEP, certain executives and AEP’s Employee Retirement Income Security Act (ERISA) Plan Administrator alleging violations of ERISA in the selection of AEP stock as an investment alternative and in the allocation of assets to AEP stock. The ERISA actions are pending in Federal District Court, Columbus, Ohio. In these actions, the plaintiffs seek recovery of an unstated amount of compensatory damages, attorney fees and costs. We filed a Motion to Dismiss these actions, which the Court denied. The cases are in the discovery stage. The Court scheduled a hearing on class certification for June 2006. We intend to continue to defend vigorously against these claims.

Natural Gas Markets Lawsuits

In November 2002, the Lieutenant Governor of California filed a lawsuit in Los Angeles County California Superior Court against forty energy companies, including AEP, and two publishing companies alleging violations of California law through alleged fraudulent reporting of false natural gas price and volume information with an intent to affect the market price of natural gas and electricity. AEP was dismissed from the case. A number of similar cases were filed in California. In addition, a number of other cases have been filed in state and federal courts in several states making essentially the same allegations under federal or state laws against the same companies. In some of these cases, AEP (or a subsidiary) is among the companies named as defendants. These cases are at various pre-trial stages. Several of these cases had been transferred to the United States District Court for the District of Nevada but subsequently remanded to California state court. In April 2005, the judge in Nevada dismissed one of the remaining cases in which AEP was a defendant on the basis of the filed rate doctrine and in December 2005, the judge dismissed two additional cases on the same ground. Plaintiffs in these cases appealed the decisions. We will continue to defend vigorously each case where an AEP company is a defendant.

Cornerstone Lawsuit

In the third quarter of 2003, Cornerstone Propane Partners filed an action in the United States District Court for the Southern District of New York against forty companies, including AEP and AEPES, seeking class certification and alleging unspecified damages from claimed price manipulation of natural gas futures and options on the NYMEX from January 2000 through December 2002. Thereafter, two similar actions were filed in the same court against a number of companies, including AEP and AEPES, making essentially the same claims as Cornerstone Propane Partners and also seeking class certification. These cases were consolidated. In January 2004, plaintiffs filed an amended consolidated complaint. The defendants filed a motion to dismiss the complaint which the Court denied. In October 2005, the Court granted the plaintiffs motion for class certification. The defendants filed a petition for leave to appeal this decision. We intend to continue to defend vigorously against these claims.

FERC Long-term Contracts

In 2002, the FERC held a hearing related to a complaint filed by certain wholesale customers located in Nevada. The complaint sought to break long-term contracts entered during the 2000 and 2001 California energy price spike which the customers alleged were “high-priced.” The complaint alleged that we sold power at unjust and unreasonable prices. In December 2002, a FERC ALJ ruled in our favor and dismissed the complaint filed by the two Nevada utilities. In 2001, the utilities filed complaints asserting that the prices for power supplied under those contracts should be lowered because the market for power was allegedly dysfunctional at the time such contracts were executed. The ALJ rejected the utilities’ complaint, held that the markets for future delivery were not dysfunctional, and that the utilities failed to demonstrate that the public interest required changes be made to the contracts. In June 2003, the FERC issued an order affirming the ALJ’s decision. The utilities’ request for a rehearing was denied. The utilities’ appeal of the FERC order is pending before the U.S. Court of Appeals for the Ninth Circuit. Management is unable to predict the outcome of this proceeding and its impact on future results of operations and cash flows.

6. GUARANTEES

There are certain immaterial liabilities recorded for guarantees in accordance with FASB Interpretation No. 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 March 31, 2006, the maximum future payments for all the LOCs are approximately $31 million with maturities ranging from July 2006 to March 2007.

GUARANTEES OF THIRD-PARTY OBLIGATIONS

SWEPCo

In connection with reducing the cost of the lignite mining contract for its Henry W. Pirkey Power Plant, SWEPCo agreed, under certain conditions, to assume the capital lease obligations and term loan payments of the mining contractor, Sabine Mining Company (Sabine). If Sabine defaults under any of these agreements, SWEPCo’s total future maximum payment exposure is approximately $55 million with maturity dates ranging from July 2006 to February 2012.

As part of the process to receive a renewal of a Texas Railroad Commission permit for lignite mining, SWEPCo provided guarantees of mine reclamation in the amount of approximately $85 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. At March 31, 2006, the cost to reclaim the mine in 2035 is estimated at approximately $39 million. This guarantee ends upon depletion of reserves estimated at 2035 plus 6 years to complete reclamation.

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. Prior to March 31, 2006, we entered into several sale agreements. 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 $2.3 billion (approximately $1 billion relates to the BOA litigation, see “Enron Bankruptcy” section of Note 5). There are no material liabilities recorded for any indemnifications.

Master Operating Lease

We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed receipt of up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At March 31, 2006, the maximum potential loss for these lease agreements was approximately $52 million ($34 million, net of tax) assuming the fair market value of the equipment is zero at the end of the lease term.

Railcar Lease

In June 2003, we entered into an agreement with BTM Capital Corporation, as lessor, to lease 875 coal-transporting aluminum railcars. The lease has an initial term of five years.

At the end of each lease term, we may (a) renew for another five-year term, not to exceed a total of twenty years, (b) purchase the railcars for the purchase price amount specified in the lease, projected at the lease inception to be the then fair market value, or (c) return the railcars and arrange a third party sale (return-and-sale option). The lease is accounted for as an operating lease. We intend to renew the lease for the full twenty years.

Under the lease agreement, the lessor is guaranteed that the sale proceeds under the return-and-sale option discussed above will equal at least the lessee obligation amount specified in the lease, which declines over the lease term from approximately 86% to 77% of the projected fair market value of the equipment. At March 31, 2006, the maximum potential loss was approximately $31 million ($20 million net of tax) assuming the fair market value of the equipment is zero at the end of the current lease term. We have other rail car lease arrangements that do not utilize this type of structure.

7. COMPANY-WIDE STAFFING AND BUDGET REVIEW

As a result of a company-wide staffing and budget review in the second quarter of 2005, we identified approximately 500 positions for elimination. Pretax severance benefits expense of $28 million was recorded (primarily in Maintenance and Other Operation within the Utility Operations segment) in 2005, primarily in the second quarter. The company subsequently made payments of $16 million during 2005. The following table shows the accrual as of December 31, 2005, the activity during the first quarter of 2006 and the remaining accrual (reflected primarily in Current Liabilities - Other) as of March 31, 2006:

	Amount (in millions)
Accrual at December 31, 2005	$	12
Less: Total Payments		8
Less: Accrual Adjustments		2
Remaining Accrual at March 31, 2006	$	2

The acrual adjustments were recorded primarily in Maintenance and Other Operation on our Condensed Consolidated Statements of Operations. The settlement of the remaining accrual is expected by the end of the second quarter of 2006.

8. DISPOSITIONS, DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

DISPOSITIONS

2006

Compresion Bajio S de R.L. de C.V. (Investments - Other segment)

In January 2002, we acquired a 50% interest in Compresion Bajio S de R.L. de C.V. (Bajio), a 600-MW power plant in Mexico. We received an indicative offer for Bajio in September 2005. The sale was completed in February 2006 for approximately $29 million with no effect on our 2006 results of operations.

2005

Houston Pipe Line Company LP (HPL) (Investments - Gas Operations segment)

During 2005, we sold our interest in HPL, 30 billion cubic feet (BCF) of working gas and working capital for approximately $1 billion, subject to a working capital and inventory true-up adjustment. Although the assets were legally transferred, it is not possible to determine all costs associated with the transfer until the Bank of America (BOA) litigation is resolved. Accordingly, we recorded the excess of the sales price over the carrying cost of the net assets transferred as a deferred gain of $379 million as of March 31, 2006 and December 31, 2005, which is reflected in Deferred Credits and Other on our accompanying Condensed Consolidated Balance Sheets. We provided an indemnity in an amount up to the purchase price to the purchaser for damages, if any, arising from litigation with BOA and a potential resulting inability to use the cushion gas (see “Enron Bankruptcy” section of Note 5). The HPL operations do not meet the criteria to be shown as discontinued operations due to continuing involvement associated with various contractual obligations. Significant continuing involvement includes cash flows from long-term gas contracts with the buyer through 2008 and the cushion gas arrangement. In addition, we continue to hold forward gas contracts not sold with the gas pipeline and storage assets.

Texas REPs (Utility Operations segment)

In December 2002, we sold two of our Texas REPs to Centrica, a UK-based provider of retail energy. The sales price was $146 million plus certain other payments including an earnings-sharing mechanism (ESM) for AEP and Centrica to share in the earnings of the sold business for the years 2003 through 2006. The method of calculating the annual earnings-sharing amount was included in the Purchase and Sales Agreement and was amended through a series of agreements that AEP and Centrica entered in March 2005. Also in March 2005, we received payments related to the ESM of $45 million and $70 million for 2003 and 2004, respectively, resulting in a pretax gain of $112 million in 2005. In March 2006, we received a payment of $70 million related to the ESM for 2005. The ESM payment for 2006 is contingent on Centrica’s future operating results and is capped at $20 million. The payments are reflected in Gain/Loss on Disposition of Assets, Net on our accompanying Condensed Consolidated Statements of Operations.

DISCONTINUED OPERATIONS

Certain of our operations were determined to be discontinued operations and have been classified as such for all periods presented. Results of operations of these businesses have been classified as shown in the following table (in millions):

Three Months ended March 31, 2006 and 2005:
	SEEBOARD (a)		U.K. Generation (b)			Total
2006 Revenue	$	-	$	-		$	-
2006 Pretax Income		-		5			5
2006 Earnings, Net of Tax		-		3	(c)		3

2005 Revenue (Expense)	$	-	$	(8	)	$	(8	)
2005 Pretax Loss		-		(8	)		(8	)
2005 Earnings (Loss), Net of Tax		6		(5	)(d)		1

(a)	Relates to purchase price true-up adjustments and tax adjustments from the sale of SEEBOARD.
(b)	The 2006 amounts relate to a release of accrued liabilities for the London office lease and tax adjustments from the sale. Amounts in 2005 relate to purchase price true-up adjustments and tax adjustments from the sale.
(c)	Earnings per share related to the UK Operations was $0.01.
(d)	Earnings per share related to the UK Operations was $(0.01).

There were no cash flows used for or provided by operating, investing or financing activities related to our discontinued operations for the three months ended March 31, 2006 and 2005.

ASSETS HELD FOR SALE

Texas Plants - Oklaunion Power Station (Utility Operations segment)

In January 2004, we signed an agreement to sell TCC’s 7.81% share of Oklaunion Power Station for approximately $43 million (subject to closing adjustments) to Golden Spread Electric Cooperative, Inc. (Golden Spread), subject to a right of first refusal by the Oklahoma Municipal Power Authority and the Public Utilities Board of the City of Brownsfield (the "nonaffiliated co-owners"). By May 2004, we received notice from the nonaffiliated co-owners of the Oklaunion Power Station, announcing their decision to exercise their right of first refusal with terms similar to the original agreement. In June 2004 and September 2004, we entered into sales agreements with both of the nonaffiliated co-owners for the sale of TCC’s 7.81% ownership of the Oklaunion Power Station. These agreements were challenged in Dallas County, Texas State District Court by Golden Spread. Golden Spread alleges that the Public Utilities Board of the City of Brownsfield exceeded its legal authority and that the Oklahoma Municipal Power Authority did not exercise its right of first refusal in a timely manner. Golden Spread requested that the court declare the co-owners’ exercise of their rights of first refusal void. The court entered a judgment in favor of Golden Spread on October 10, 2005. TCC and the nonaffiliated co-owners filed an appeal to the Fifth State Court of Appeals in Dallas. The case was briefed and argued before the court and is awaiting a decision. We cannot predict when these issues will be resolved. We do not expect the sale to have a significant effect on our future results of operations. TCC’s assets related to the Oklaunion Power Station have been classified as Assets Held for Sale on our Condensed Consolidated Balance Sheets at March 31, 2006 and December 31, 2005. The plant does not meet the “component-of-an-entity” criteria because it does not have cash flows that can be clearly distinguished operationally. The plant also does not meet the “component-of-an-entity” criteria for financial reporting purposes because it does not operate individually, but rather as a part of the AEP System, which includes all of the generation facilities owned by our Registrant Subsidiaries.

Assets Held for Sale at March 31, 2006 and December 31, 2005 are as follows:

	March 31,		December 31,
Texas Plants	2006		2005
Assets:	(in millions)
Other Current Assets	$	1	$	1
Property, Plant and Equipment, Net		43		43
Total Assets Held for Sale	$	44	$	44

9. BENEFIT PLANS

Components of Net Periodic Benefit Cost

The following table provides the components of our net periodic benefit cost for the following plans for the three months ended March 31, 2006 and 2005:

	Pension Plans						Other Postretirement Benefit Plans
	2006			2005			2006			2005
	(in millions)
Service Cost	$	24		$	23		$	10		$	11
Interest Cost		57			56			25			27
Expected Return on Plan Assets		(83	)		(77	)		(23	)		(23	)
Amortization of Transition Obligation		-			-			7			7
Amortization of Net Actuarial Loss		20			13			5			7
Net Periodic Benefit Cost	$	18		$	15		$	24		$	29

10. STOCK-BASED COMPENSATION

The Amended and Restated American Electric Power System Long-Term Incentive Plan (the Plan) 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 shares awards, which include performance units, restricted shares and restricted stock units. The Board of Directors and shareholders both adopted the original Plan in 2000 and the amended and restated version in 2005. Except for 10,000 stock options granted in the third quarter of 2005, we have not granted stock options since 2004. The following sections provide further information regarding each type of stock-based compensation award we have granted.

We adopted SFAS 123R, effective January 1, 2006. See the SFAS 123 (revised 2004) “Share-Based Payment” section of Note 2 for additional information.

Stock Options

For all stock options previously granted, the exercise price equaled or exceeded the market price of AEP’s common stock on the date of grant. Historically we have granted stock options with a ten-year term that generally vest, subject to the participant’s continued employment, in approximately equal 1/3 increments on January 1^st of the year following the first, second and third anniversary of the grant date. Compensation cost for stock options is recorded over the vesting period based on the fair value on the grant date. The Plan does not specify a maximum contractual term for stock options.

CSW maintained a stock option plan prior to the merger with AEP in 2000. Effective with the merger, all CSW stock options outstanding were converted into AEP stock options at an exchange ratio of one CSW stock option for 0.6 of an AEP stock option. The exercise price for each CSW stock option was adjusted for the exchange ratio. Outstanding CSW stock options will continue in effect until all options are exercised, cancelled, expired or forfeited. Under the CSW stock option plan, the option price was equal to the fair market value of the stock on the grant date. All CSW options fully vested upon the completion of the merger and expire 10 years after their original grant date.

AEP did not award any stock options during the three months ended March 31, 2006 and 2005.

The total fair value of stock options vested during the three months ended March 31, 2006 and 2005 were $3,664,624 and $5,030,424, respectively. The total intrinsic value of options exercised during the three months ended March 31, 2006 and 2005 was $1,389,409 and $4,319,995, respectively. Intrinsic value is calculated as market price at exercise date less the option exercise price.

A summary of AEP stock option transactions during the three months ended March 31, 2006 is as follows:

	Options			Weighted Average Exercise Price

Outstanding at beginning of quarter		6,221,839		$	34.16
Granted		-			N/A
Exercised/converted		(172,722	)		28.67
Expired		(87,611	)		48.43
Forfeited		-			N/A
Outstanding at end of quarter		5,961,506			34.11

Options exercisable at end of quarter		5,689,652		$	34.34

Weighted average exercise price of options:
Granted above Market Price		-		$	N/A
Granted at Market Price		-		$	N/A

The following table summarizes information about AEP stock options outstanding at March 31, 2006.

Options Outstanding

2006 Range of Exercise Prices	Number Outstanding		Weighted Average Remaining Life		Weighted Average Exercise Price		Aggregate Intrinsic Value
			(in years)
$25.73 - $27.95		1,465,615		6.9	$	27.37	$	9,693,895
$30.76 - $38.65		4,110,408		4.6		35.45		823,032
$43.79 - $49.00		385,483		5.4		45.52		-
		5,961,506		5.2		34.11	$	10,516,927

The following table summarizes information about AEP stock options exercisable at March 31, 2006.

Options Exercisable

2006 Range of Exercise Prices	Number Exercisable		Weighted Average Remaining Life		Weighted Average Exercise Price		Aggregate Intrinsic Value
			(in years)
$25.73 - $27.95		1,260,528		6.1	$	27.29	$	8,473,587
$30.76 - $38.65		4,050,741		3.6		35.50		602,951
$43.79 - $49.00		378,383		5.0		45.49		-
		5,689,652		4.2		34.34	$	9,076,538

The proceeds received from exercised stock options are included in common stock and paid-in capital.

For options issued through December 31, 2005, the grant date fair value of each option award was estimated using a Black-Scholes option-pricing model with weighted average assumptions. Expected volatilities are estimated using the historical monthly volatility of our common stock for the 36-month period prior to each grant. A seven-year average expected term is also assumed. The risk-free rate is the yield for U.S. Treasury securities with a remaining life equal to the expected seven-year term of AEP stock options on the grant date.

Performance Units

Our performance units are equal in value to an equivalent number of shares of AEP common stock. The number of performance units held is multiplied by a performance score to determine the actual number of performance units realized. The performance score is determined at the end of the performance period based on performance measure(s) established for each grant at the beginning of the performance period by the Human Resources Committee of the Board of Directors (HR Committee) and can range from 0 percent to 200 percent. Performance units are typically paid in cash at the end of a three-year performance and vesting period, unless they are needed to satisfy a participant’s stock ownership requirement, in which case they are mandatorily deferred as phantom stock units (“AEP Career Shares”) until after the end of the participant’s AEP career. AEP Career Shares have a value equivalent to the market value of an equal number of AEP common shares and are generally paid in cash after the participant’s termination of employment. Amounts equivalent to cash dividends on both performance units and AEP Career Shares accrue as additional units. The compensation cost for performance units is recorded over the vesting period and the liability for both the performance units and AEP Career Shares is adjusted for changes in value. The vesting period of all performance units is three years.

We awarded performance units and reinvested dividends on outstanding performance units and AEP Career Shares for the three months ended March 31, 2006 and 2005 as follows:

	2006		2005
Performance Units
Awarded Units		864,420		1,012,597
Unit Fair Value at Grant Date	$	37.36	$	34.02
Vesting Period (years)		3		3

	2006			2005
Performance Units and AEP Career Shares (Reinvested Dividends Portion)
Awarded Units		30,277		23,939
Unit Fair Value at Grant Date	$	35.31	$	34.21
Vesting Period (years)		3		3

In January 2006, the HR Committee certified a performance score of 49% for performance units originally granted for the 2003 through 2005 performance period. As a result, 108,486 performance units were earned. Of this amount 33,296 were mandatorily deferred as AEP Career Shares, 4,360 were voluntarily deferred into the Incentive Compensation Deferral Program and the remainder were paid in cash. The cash payout for these performance units was $2,629,537 for the three months ended March 31, 2006.

The score for the 2002 through 2004 performance period was discretionarily reduced to 0% by the HR Committee so no performance units were earned, paid or deferred during the three months ended March 31, 2005.

The cash payouts for AEP Career Share distributions, which occur after a participant’s termination of employment, for the three months ended March 31, 2006 and 2005 were $475,685 and $564,598, respectively.

The performance unit scores for all open performance periods are dependent on two equally weighted performance measures: three-year total shareholder return measured relative to the S&P Utilities Index and three-year cumulative earnings per share measured relative to a board-approved target. The value of each performance unit earned equals the average closing price of AEP common stock for the last 20 days of the performance period.

The fair value of performance unit awards is based on the estimated performance score and the current 20-day average closing price of AEP common stock at the date of valuation.

Restricted Shares and Restricted Stock Units

We granted 300,000 restricted shares to the Chairman, President and CEO on January 2, 2004 upon the commencement of his AEP employment. Of these restricted shares 50,000 vested on January 1, 2005 and 50,000 vested on January 1, 2006. The remaining 200,000 restricted shares vest, subject to his continued employment, in approximately equal thirds on November 30, 2009, 2010 and 2011. The maximum term for these restricted shares is eight years. We have not granted other restricted shares. Dividends on our restricted shares are paid in cash.

We also grant restricted stock units, which generally vest, subject to the participant’s continued employment, over at least three years in approximately equal annual increments on the anniversaries of the grant date. Amounts equivalent to dividends paid on AEP shares accrue as additional restricted stock units that vest on the last vesting date associated with the underlying units. Compensation cost is measured at fair value on the grant date and recorded over the vesting period. Fair value is determined by multiplying the number of units granted by the grant date market price. The maximum contractual term of these restricted stock units is six years.

In January 2006, we also granted restricted stock units with performance vesting conditions to certain employees who are integral to our project to design and build an IGCC power plant. Twenty percent of these awards vest on each of the first three anniversaries of the grant date. An additional 20% vest on the date the IGCC plant achieves commercial operations. The remaining 20% vest one year after the IGCC plant achieves commercial operations, subject to achievement of plant availability targets.

We awarded restricted stock units, including units awarded for dividends, for the three months ended March 31, 2006 and 2005 as follows:

	2006		2005
Restricted Stock Units
Awarded Units		37,199		27,100
Weighted Average Grant Date Fair Value	$	35.80	$	33.11

The total fair value of restricted shares and restricted stock units vested during the three months ended March 31, 2006 and 2005 were $2,279,551 and $2,132,922, respectively. The total intrinsic value of restricted shares and restricted stock units vested during the three months ended March 31, 2006 and 2005 was $2,944,138 and $2,577,752, respectively.

A summary of the status of our nonvested restricted shares and restricted stock units as of March 31, 2006, and changes during the three months ended March 31, 2006, are presented below:

Nonvested Restricted Shares and Restricted Stock Units	Shares/Units			Weighted Average Grant Date Fair Value

Nonvested at beginning of quarter		496,716		$	32.19
Granted		37,199			35.80
Vested		(78,944	)		28.88
Forfeited		(565	)		32.81
Nonvested at end of quarter		454,406			33.06

The total aggregate intrinsic value of nonvested restricted shares and restricted stock units as of March 31, 2006 was $15,458,892 and the weighted average remaining contractual life was 3.14 years.

Share-based Compensation Plans

Compensation cost for share-based payment arrangements recognized in income for the three months ended March 31, 2006 and 2005 was $2,429,868 and $2,916,484, respectively. The actual tax benefit realized for the tax deductions from compensation cost from share-based payment arrangements recognized in income for the three months ended March 31, 2006 and 2005 totaled $850,454 and $1,020,769, respectively. The total compensation cost capitalized in relation to the cost of an asset for the three months ended March 31, 2006 and 2005 was $578,434 and $401,159, respectively.

During the three months ended March 31, 2006 and 2005, there were no significant modifications affecting any of our share-based payment arrangements.

As of March 31, 2006, there was $45,936,136 of total unrecognized compensation cost related to unvested share-based compensation arrangements granted under the Plan. Unrecognized compensation cost related to the performance units and AEP Career Shares will change as the liability is revalued each period and forfeitures for all award types are realized. Our unrecognized compensation cost will be recognized over a weighted-average period of 1.67 years.

Cash received from stock options exercised during the three months ended March 31, 2006 and 2005 was $4,952,298 and $15,153,465, respectively. The actual tax benefit realized for the tax deductions from stock options exercised during the three months ended March 31, 2006 and 2005 totaled $486,293 and $1,515,268, respectively.

Our practice is to use authorized but unissued shares to fulfill share commitments for stock option exercises and restricted stock unit vesting. Although we do not currently anticipate any changes to this practice, we could use reacquired shares, shares acquired in the open market specifically for distribution under the Plan or any combination thereof for this purpose. The number of new shares issued to fulfill vesting restricted stock units is generally reduced, at the participant’s election, to offset AEP’s tax withholding obligation.

11. BUSINESS SEGMENTS

As outlined in our 2005 Annual Report, our business strategy and the core of our business are to focus on domestic electric utility operations. Our previous decision that we no longer pursue business interests outside of the footprint of our domestic core utility assets led us to embark on a divestiture of such noncore assets. Consequently, the significance of our three Investments segments has declined.

Our segments and their related business activities are as follows:

AEP TEXAS NORTH CO 10-Q